System and method for estimating photovoltaic energy through empirical derivation with the aid of a digital computer

ABSTRACT

The accuracy of photovoltaic simulation modeling is predicated upon the selection of a type of solar resource data appropriate to the form of simulation desired. Photovoltaic power simulation requires irradiance data. Photovoltaic energy simulation requires normalized irradiation data. Normalized irradiation is not always available, such as in photovoltaic plant installations where only point measurements of irradiance are sporadically collected or even entirely absent. Normalized irradiation can be estimated through several methodologies, including assuming that normalized irradiation simply equals irradiance, directly estimating normalized irradiation, applying linear interpolation to irradiance, applying linear interpolation to clearness index values, and empirically deriving irradiance weights. The normalized irradiation can then be used to forecast photovoltaic fleet energy production.

This invention was made with State of California support under AgreementNumber 722. The California Public Utilities Commission of the State ofCalifornia has certain rights to this invention.

FIELD

This application relates in general to photovoltaic power generationfleet planning and operation and, in particular, to a system and methodfor estimating photovoltaic energy empirical derivation with the aid ofa digital computer.

BACKGROUND

The manufacture and usage of photovoltaic systems has advancedsignificantly in recent years due to a continually growing demand forrenewable energy resources. The cost per watt of electricity generatedby photovoltaic systems has decreased more dramatically than in earliersystems, especially when combined with government incentives offered toencourage photovoltaic power generation. Typically, when integrated intoa power grid, photovoltaic systems are collectively operated as a fleet,although the individual systems in the fleet may be deployed atdifferent physical locations within a geographic region.

Grid connection of photovoltaic power generation fleets is a fairlyrecent development. A power grid is an electricity generation,transmission, and distribution infrastructure that delivers electricityfrom supplies to consumers. As electricity is consumed almostimmediately upon production, power generation and consumption must bebalanced across the entire power grid. A large power failure in one partof the grid could cause electrical current to reroute from remainingpower generators over transmission lines of insufficient capacity, whichcreates the possibility of cascading failures and widespread poweroutages.

Photovoltaic fleets connected to a power grid are expected to exhibitpredictable generation behaviors. Accurate production data isparticularly crucial when a photovoltaic fleet makes a significantcontribution to a power grid's overall energy mix. Various kinds ofphotovoltaic plant production forecasts can be created and combined intophotovoltaic power generation fleet forecasts, such as described incommonly-assigned U.S. Pat. Nos. 8,165,811; 8,165,812; 8,165,813, allissued to Hoff on Apr. 24, 2012; U.S. Pat. Nos. 8,326,535 and 8,326,536,issued to Hoff on Dec. 4, 2012; U.S. Pat. No. 8,335,649, issued to Hoffon Dec. 18, 2012; and U.S. Pat. No. 8,437,959, issued to Hoff on May 7,2013, the disclosures of which are incorporated by reference.

Photovoltaic production forecasting first requires choosing a type ofsolar resource appropriate to the form of simulation. The solar resourcedata is then combined with each plant's system configuration in aphotovoltaic simulation model, which generates a forecast ofphotovoltaic production. Confusion exists about the relationship betweenirradiance and irradiation, their respective applicability toforecasting, and how to correctly calculate normalized irradiation. Inessence, solar power forecasting requires irradiance, which is aninstantaneous measure of solar radiation that can be derived from asingle ground-based observation, satellite imagery, numerical weatherprediction models, or other sources. Solar energy forecasting requiresnormalized irradiation, which is an interval measure of solar radiationmeasured or projected over a time period.

The distinction between irradiance and normalized irradiation isfrequently overlooked, yet confusing these two solar resources is causalto photovoltaic power and energy simulation inaccuracies. The rate andquantity terms used in photovoltaic production forecasting, irradianceand normalized irradiation, are semantically related and easily mixedup, whereas other fields use linguistically distinct terms, such astransportation, which refers to rate as speed and quantity as distance.As well, irradiance and normalized irradiation reverse conventional usesof time as measures of proportionality, where rate is merely expressedas W/m² (watts per square meter) and non-normalized quantity, that is,irradiation, is expressed as W/m²/h (watts per square meter per hour),or, in normalized form, using the same units as rate, W/m². Using thesame units for both rate and quantity contributes to confusion.Irradiance and normalized irradiation are only guaranteed to beequivalent if the irradiance is constant over the time interval overwhich normalized irradiation is solved. This situation rarely occurssince the sun's position in the sky is constantly changing, albeit at avery slow rate.

In addition to applying the correct type of solar resource, the physicalconfiguration of each photovoltaic system is critical to forecastingaggregate plant power output. Inaccuracies in the assumed specificationsof individual photovoltaic system configurations directly translate toinaccuracies in their power output forecasts. Individual photovoltaicsystem configurations may vary based on power rating and electricalcharacteristics and by their operational features, such azimuth and tiltangles and shading or other physical obstructions.

Photovoltaic system power output is particularly sensitive to shadingdue to cloud cover. As well, photovoltaic fleets that combine individualplants physically scattered over a geographical area may be subject todifferent weather conditions due to cloud cover and cloud speed with aneffect on aggregate fleet power output. Photovoltaic fleets operatingunder cloudy conditions can exhibit variable and potentiallyunpredictable performance. Conventionally, fleet variability isdetermined by collecting and feeding direct power measurements fromindividual photovoltaic systems or indirectly-derived power measurementsinto a centralized control computer or similar arrangement. However, thepracticality of such an approach diminishes as the number of systems,variations in system configurations, and geographic dispersion of thefleet grow.

For instance, one direct approach to obtaining high speed time seriespower production data from a fleet of existing photovoltaic systems isto install physical meters on every photovoltaic system, record theelectrical power output at a desired time interval, such as every 10seconds, and sum the recorded output across all photovoltaic systems inthe fleet at each time interval. An equivalent direct approach toobtaining high speed time series power production data is to collectsolar irradiance data from a dense network of weather monitoringstations covering all anticipated locations at the desired timeinterval, use a photovoltaic performance model to simulate the highspeed time series output data for each photovoltaic system individually,and then sum the results at each time interval.

With either direct approach to obtaining high speed time series powerproduction data, several difficulties arise. First, in terms of physicalplant, installing, operating, and maintaining meters and weatherstations is expensive and detracts from cost savings otherwise affordedthrough a renewable energy source. Similarly, collecting, transmitting,and storing high speed data for every location requires collateral datacommunications and processing infrastructure. Moreover, data loss canoccur if instrumentation or data communications fail.

Second, both direct approaches only work when and where meters arepre-installed; thus, high speed time series power production data isunavailable for all other locations, time periods, and photovoltaicsystem configurations. Both direct approaches also cannot be used todirectly forecast future photovoltaic system performance since metersmust be physically present at the time and location of interest. Dataalso must be recorded at the time resolution that corresponds to thedesired output time resolution. While low time-resolution results can becalculated from high resolution data, the opposite calculation is notpossible.

The few solar data networks that exist in the United States, such as theARM network, described in G. M. Stokes et al., “The AtmosphericRadiation Measurement (ARM) Program: Programmatic Background and Designof the Cloud and Radiation Test Bed,” Bull. of Am. Meteor. Soc., Vol.75, pp. 1201-1221 (1994), the disclosure of which is incorporated byreference, and the SURFRAD network, lack high density networks and donot collect data at a fast rate. These limitations have promptedresearchers to evaluate other alternatives, including dense networks ofsolar monitoring devices in a few limited locations, such as describedin S. Kuszamaul et al., “Lanai High-Density Irradiance Sensor Networkfor Characterizing Solar Resource Variability of MW-Scale PV System.”35^(th) Photovoltaic Specialists Conf., Honolulu, HI (Jun. 20-25, 2010),and R. George, “Estimating Ramp Rates for Large PV Systems Using a DenseArray of Measured Solar Radiation Data,” Am. Solar Energy Society AnnualConf. Procs., Raleigh, NC (May 18, 2011), the disclosures of which areincorporated by reference. As data was collected, the researchersexamined the data to determine whether there were underlying models thatcould translate results from these devices to photovoltaic fleetproduction operating over a broader geographical area, yet actualtranslation of the data was not provided.

In addition, satellite irradiance data for specific locations and timeperiods have been combined with randomly selected high speed data from alimited number of ground-based weather stations, such as described inCAISO 2011. “Summary of Preliminary Results of 33% Renewable IntegrationStudy—2010,” Cal. Pub. Util. Comm. LTPP No. R.10-05-006 (Apr. 29, 2011)and J. Stein, “Simulation of 1-Minute Power Output from Utility-ScalePhotovoltaic Generation Systems,” Am. Solar Energy Soc. Annual Conf.Procs., Raleigh, NC (May 18, 2011), the disclosures of which areincorporated by reference. This approach, however, does not produce timesynchronized photovoltaic fleet variability for specific time periodsbecause the locations of the ground-based weather stations differ fromthe actual locations of the fleet.

The concerns relating to high speed time series power production dataacquisition also apply to photovoltaic fleet output estimation. Creatinga fleet power forecast requires evaluation of the irradiance expectedover each location within a photovoltaic fleet, which must be inferredfor those locations where measurement-based sources of historical solarirradiance data are lacking. As well, irradiance derived from satelliteimagery requires additional processing prior to use in simulating fleettime series output data. Finally, simulating fleet energy output orcreating a fleet energy forecast requires evaluation of the normalizedirradiation expected over the period of interest. Normalized irradiationis analogous to the average irradiance measured over a time interval,yet normalized irradiation is not always available, such as insituations where only point measurements of irradiance are sporadicallycollected or even entirely absent.

Therefore, a need remains for an approach to facilitating accuratephotovoltaic power simulation by providing an appropriate type of solarresource, regardless of whether physically measured, for use inforecasting photovoltaic fleet power and energy output.

SUMMARY

The accuracy of photovoltaic simulation modeling is predicated upon theselection of a type of solar resource data appropriate to the form ofsimulation desired. Photovoltaic power simulation requires irradiancedata. Photovoltaic energy simulation requires normalized irradiationdata. Normalized irradiation is not always available, such as inphotovoltaic plant installations where only point measurements ofirradiance are sporadically collected or even entirely absent.Normalized irradiation can be estimated through several methodologies,including assuming that normalized irradiation simply equals irradiance,directly estimating normalized irradiation, applying linearinterpolation to irradiance, applying linear interpolation to clearnessindex values, and empirically deriving irradiance weights. Thenormalized irradiation can then be used to forecast photovoltaic fleetenergy production.

In one embodiment, a system and method for estimating photovoltaicenergy through empirical derivation with the aid of a digital computeris provided. Solar irradiance data is obtained that includes a set ofirradiance observations that have been recorded for a location at whicha photovoltaic plant can be operated with each irradiance observation inthe set being separated by regular intervals of time. Measuredirradiance associated with at least some of the irradiance observationsis obtained. A set of clear sky irradiance is obtained, with each clearsky irradiance in the set corresponding to one of the irradianceobservations. A weighting factor array empirically deriving using anoptimization approach and using at least some of the measured irradianceand the irradiance observations associated with the at least somemeasured irradiance. A set of normalized irradiation is estimated, witheach normalized irradiation in the set corresponding to one of theirradiance observations, using the weighing factor array and theirradiance observations. A time series of clearness indexes is formed,with each clearness index in the time series corresponding to one of theirradiance observations, each clearness index including a ratio of theirradiance observation's corresponding normalized irradiation estimateand the irradiance observation's corresponding clear sky irradiance. Aphotovoltaic energy production for the photovoltaic plant is forecastedas a function of the time series of the clearness indexes andphotovoltaic plant's power rating, wherein the steps are performed by atleast one suitably-programmed computer.

Notable elements of this methodology non-exclusively include:

-   -   (1) Employing a fully derived statistical approach to generating        high-speed photovoltaic fleet production data;    -   (2) Using a small sample of input data sources as diverse as        ground-based weather stations, existing photovoltaic systems, or        solar data calculated from satellite images;    -   (3) Producing results that are usable for any photovoltaic fleet        configuration;    -   (4) Supporting any time resolution, even those time resolutions        faster than the input data collection rate;    -   (5) Providing results in a form that is useful and usable by        electric power grid planning and operation tools;    -   (6) Solving solar irradiance correlation matrices as needed for        photovoltaic fleet output estimation in a linear solution space;        and

(7) Providing both instantaneous irradiance measures and time intervalnormalized irradiance measures for respective use in photovoltaic powerand energy calculations, simulations and forecasting.

Still other embodiments will become readily apparent to those skilled inthe art from the following detailed description, wherein are describedembodiments by way of illustrating the best mode contemplated. As willbe realized, other and different embodiments are possible and theembodiments' several details are capable of modifications in variousobvious respects, all without departing from their spirit and the scope.Accordingly, the drawings and detailed description are to be regarded asillustrative in nature and not as restrictive.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a flow diagram showing a computer-implemented method forestimating photovoltaic energy generation for use in photovoltaic fleetoperation in accordance with one embodiment.

FIG. 2 is a block diagram showing a computer-implemented system forestimating photovoltaic energy generation for use in photovoltaic fleetoperation in accordance with one embodiment.

FIG. 3 is a graph depicting, by way of example, ten hours of time seriesirradiance data collected from a ground-based weather station with10-second resolution.

FIG. 4 is a graph depicting, by way of example, the clearness index thatcorresponds to the irradiance data presented in FIG. 3 .

FIG. 5 is a graph depicting, by way of example, the change in clearnessindex that corresponds to the clearness index presented in FIG. 4 .

FIG. 6 is a graph depicting, by way of example, the irradiancestatistics that correspond to the clearness index in FIG. 4 and thechange in clearness index in FIG. 5 .

FIG. 7 is a flow diagram showing a function for determining variance foruse with the method of FIG. 1 .

FIG. 8 is a block diagram showing, by way of example, nine evenly-spacedpoints within a three-by-three correlation region for evaluation by thefunction of FIG. 7 .

FIG. 9 is a block diagram showing, by way of example, 16 evenly-spacedpoints within a three-by-three correlation region for evaluation by thefunction of FIG. 7 .

FIG. 10 is a graph depicting, by way of example, the number ofcalculations required when determining variance using three differentapproaches.

FIG. 11 is a screen shot showing, by way of example, a user interface ofthe SolarAnywhere service.

FIGS. 12A-12B are graphs showing, by way of example, a sample day ofsolar irradiance plotted respectively based on the centered on satellitemeasurement time and standard top of hour, end of period integrationformats.

FIGS. 13A-13B are graphs respectively showing, by way of example, asample day of irradiance and clearness indexes.

FIGS. 14A-14B are graphs respectively showing, by way of example,two-hour periods of the irradiance and clearness indexes of the sampleday of FIGS. 12A-12B.

FIG. 15 is a graph showing, by way of example, normalized irradiationequated to irradiance based on the irradiance plotted in FIG. 14A.

FIG. 16 is a graph showing, by way of example, normalized irradiationdetermined through linear interpolation of the irradiance plotted inFIG. 14A.

FIG. 17 is a graph showing, by way of example, three cases ofdetermining normalized irradiation through linear interpolation of theirradiance plotted in FIG. 14A.

FIG. 18 is a table presenting, by way of example, the normalizedirradiation calculated for the three cases of FIG. 17 .

FIGS. 19A-19B are graphs respectively showing, by way of example,determining clearness indexes through linear interpolation of theirradiance plotted of FIGS. 12A-12B.

FIG. 20 is a table presenting, by way of example, the weighting factorsfor calculating normalized irradiation for start at top of hour (orhalf-hour for Enhanced Resolution data) with end of period integrationfor the three cases of FIG. 17 .

FIG. 21 is a table presenting, by way of example, the relative MeanAbsolute Error for irradiance and normalized irradiation for thenormalized irradiation estimates for the ten locations and resolutionscenarios.

FIG. 22 is a graph showing, by way of example, the relative reduction inrelative Mean Absolute Error for the normalized irradiation estimatesfor the ten locations and resolution scenarios.

FIG. 23 is a set of graphs showing, by way of example, StandardResolution data (half-hour, 1-km) in Hanford, CA, 2012 for the tunedversus un-tuned irradiance and normalized irradiation.

FIG. 24 is a set of graphs showing, by way of example, EnhancedResolution data (half-hour, 1-km) in Hanford, CA, 2012 for the tunedversus un-tuned irradiance and normalized irradiation.

FIG. 25 is a set of graphs showing, by way of example, EnhancedResolution data (half-hour, 1-km) in Campbell, Hawaii, first half of2012 for the tuned versus un-tuned irradiance and normalizedirradiation.

FIG. 26 is a set of graphs showing, by way of example, StandardResolution data (half-hour, 1-km) in Penn State, PA, 2012 for the tunedversus un-tuned irradiance and normalized irradiation.

FIG. 27 is a set of graphs showing, by way of example, StandardResolution data (half-hour, 1-km) in Boulder, CO, 2012 for the tunedversus un-tuned irradiance and normalized irradiation.

FIGS. 28A-28B are photographs showing, by way of example, the locationsof the Cordelia Junction and Napa high density weather monitoringstations.

FIGS. 29A-29B are graphs depicting, by way of example, the adjustmentfactors plotted for time intervals from 10 seconds to 300 seconds.

FIGS. 30A-30F are graphs depicting, by way of example, the measured andpredicted weighted average correlation coefficients for each pair oflocations versus distance.

FIGS. 31A-31F are graphs depicting, by way of example, the sameinformation as depicted in FIGS. 30A-30F versus temporal distance.

FIGS. 32A-32F are graphs depicting, by way of example, the predictedversus the measured variances of clearness indexes using differentreference time intervals.

FIGS. 33A-33F are graphs depicting, by way of example, the predictedversus the measured variances of change in clearness indexes usingdifferent reference time intervals.

FIGS. 34A-34F are graphs and a diagram depicting, by way of example,application of the methodology described herein to the Napa network.

FIG. 35 is a graph depicting, by way of example, an actual probabilitydistribution for a given distance between two pairs of locations, ascalculated for a 1,000 meter×1,000 meter grid in one square meterincrements.

FIG. 36 is a graph depicting, by way of example, a matching of theresulting model to an actual distribution.

FIG. 37 is a graph depicting, by way of example, results generated byapplication of Equation (85).

FIG. 38 is a graph depicting, by way of example, the probability densityfunction when regions are spaced by zero to five regions.

FIG. 39 is a graph depicting, by way of example, results by applicationof the model.

DETAILED DESCRIPTION

Photovoltaic cells employ semiconductors exhibiting a photovoltaiceffect to generate direct current electricity through conversion ofsolar irradiance. Within each photovoltaic cell, light photons exciteelectrons in the semiconductors to create a higher state of energy,which acts as a charge carrier for the electrical current. The directcurrent electricity is converted by power inverters into alternatingcurrent electricity, which is then output for use in a power grid orother destination consumer. A photovoltaic system uses one or morephotovoltaic panels that are linked into an array to convert sunlightinto electricity. A single photovoltaic plant can include one or more ofthese photovoltaic arrays. In turn, a collection of photovoltaic plantscan be collectively operated as a photovoltaic fleet that is integratedinto a power grid, although the constituent photovoltaic plants withinthe fleet may actually be deployed at different physical locationsspread out over a geographic region.

To aid with the planning and operation of photovoltaic fleets, whetherat the power grid, supplemental, or standalone power generation levels,photovoltaic output power and energy production and variability must beestimated expeditiously, particularly when forecasts are needed in thenear term. FIG. 1 is a flow diagram showing a computer-implementedmethod 10 for estimating photovoltaic energy generation for use inphotovoltaic fleet operation in accordance with one embodiment. Themethod 10 can be implemented in software and execution of the softwarecan be performed on a computer system, such as further described infra,as a series of process or method modules or steps.

A time series of solar irradiance or photovoltaic (“PV”) data is firstobtained (step 11) for a set of locations representative of thegeographic region within which the photovoltaic fleet is located orintended to operate, as further described infra with reference to FIG. 3. Each time series contains solar irradiance observations, which areinstantaneous measures associated with a single observation time thatare measured or derived, then electronically recorded at a knownsampling rate at fixed time intervals, such as at half-hour intervals,over successive observational time periods. The solar irradianceobservations can include solar irradiance measured by a representativeset of ground-based weather stations (step 12), existing photovoltaicsystems (step 13), satellite observations (step 14), or some combinationthereof. Other sources of the solar irradiance data are possible,including numeric weather prediction models.

Next, the solar irradiance data in the time series is converted overeach of the time periods, such as at half-hour intervals, into a set ofglobal horizontal irradiance (GHI) clearness indexes, which arecalculated relative to clear sky global horizontal irradiance based onthe type of solar irradiance data, such as described incommonly-assigned U.S. patent application, entitled“Computer-Implemented Method for Tuning Photovoltaic Power GenerationPlant Forecasting,” Ser. No. 13/677,175, filed Nov. 14, 2012, pending,the disclosure of which is incorporated by reference. The set ofclearness indexes can be interpreted into irradiance statistics (step15), as further described infra with reference to FIGS. 4-6 . The solarirradiance data and, in a further embodiment, the set of clearnessindexes, can also be interpreted into normalized irradiation (step 18),as further described infra with reference to FIGS. 11-27 .

Output data that can include power and energy data, including a timeseries of the power statistics for the photovoltaic plant, are generated(step 17) as a function of the irradiance statistics, photovoltaic plantconfiguration, and, if applicable, normalized irradiation (step 16). Thephotovoltaic plant configuration includes power generation and locationinformation, including direct current (“DC”) plant and photovoltaicpanel ratings; number of power inverters; latitude, longitude andelevation; sampling and recording rates; sensor type, orientation, andnumber; voltage at point of delivery; tracking mode (fixed, single-axistracking, dual-axis tracking), azimuth angle, tilt angle, row-to-rowspacing, tracking rotation limit, and shading or other physicalobstructions. In a further embodiment, photovoltaic plant configurationspecifications can be inferred, which can be used to correct, replaceor, if configuration data is unavailable, stand-in for the plant'sspecifications, such as described in commonly-assigned U.S. Pat. No.8,682,585, the disclosure of which is incorporated by reference. Othertypes of information can also be included as part of the photovoltaicplant configuration. The resultant high-speed time series plantperformance data can be combined to estimate photovoltaic fleet poweroutput and variability, such as described in commonly-assigned U.S. Pat.Nos. 8,165,811; 8,165,812; 8,165,813; 8,326,535; 8,335,649; and8,326,536, cited supra, for use by power grid planners, operators andother interested parties.

The calculated irradiance statistics are combined with the photovoltaicfleet configuration to generate the high-speed time series photovoltaicproduction data. In a further embodiment, the foregoing methodology mayalso require conversion of weather data for a region, such as data fromsatellite regions, to average point weather data. A non-optimizedapproach would be to calculate a correlation coefficient matrixon-the-fly for each satellite data point. Alternatively, a conversionfactor for performing area-to-point conversion of satellite imagery datais described in commonly-assigned U.S. Pat. Nos. 8,165,813 and8,326,536, cited supra.

Each forecast of power production data for a photovoltaic plant predictsthe expected power or energy output over a forecast period. FIG. 2 is ablock diagram showing a computer-implemented system 20 for estimatingphotovoltaic energy generation for use in photovoltaic fleet operationin accordance with one embodiment. Time series power output data 32 fora photovoltaic plant is generated using observed field conditionsrelating to overhead sky clearness. Solar irradiance 23 relative toprevailing cloudy conditions 22 in a geographic region of interest ismeasured. Solar irradiance 23 measures the instantaneous power of solarradiation per unit area incident on a surface. On the other hand, solarirradiation (not shown), which is a computed value, measures the solarradiation energy received on a unit area incident on a surface asrecorded over an interval of time. Time-averaged solar irradiance istermed normalized irradiation.

Direct solar irradiance measurements can be collected by ground-basedweather stations 24. Solar irradiance measurements can also be derivedor inferred by the actual power output of existing photovoltaic systems25. Additionally, satellite observations 26 can be obtained for thegeographic region. In a further embodiment, the solar irradiance can begenerated, derived or inferred by numerical weather prediction models.Both the direct and inferred solar irradiance measurements areconsidered to be sets of point values that relate to a specific physicallocation, whereas satellite imagery data is considered to be a set ofarea values that need to be converted into point values, such asdescribed in commonly-assigned U.S. Pat. Nos. 8,165,813 and 8,326,536,cited supra. Still other sources of solar irradiance measurements arepossible.

The solar irradiance measurements are centrally collected by a computersystem 21 or equivalent computational device. The computer system 21executes the methodology described supra with reference to FIG. 1 and asfurther detailed herein to generate time series power data 26 and otheranalytics, which can be stored or provided 27 to planners, operators,and other parties for use in solar power generation 28 planning andoperations. In a further embodiment, the computer system 21 executes amethodology for inferring operational specifications of a photovoltaicpower generation system, such as described in commonly-assigned U.S.Pat. No. 8,682,585, the disclosure of which is incorporated byreference, which can be stored or provided 27 to planners and otherinterested parties for use in predicting individual and fleet poweroutput generation. In a still further embodiment, the computer system 21executes the methodology described infra beginning with reference toFIG. 11 to determine normalized irradiation, which can similarly bestored or provided 27 to planners and other interested parties for usein predicting individual and fleet energy output generation. Still otherforms of power and energy data are possible.

The data feeds 29 a-c from the various sources of solar irradiance dataneed not be high speed connections; rather, the solar irradiancemeasurements can be obtained at an input data collection rate, andapplication of the methodology described herein provides the generationof an output time series at any time resolution, even faster than theinput time resolution. The computer system 21 includes hardwarecomponents conventionally found in a general purpose programmablecomputing device, such as a central processing unit, memory, userinterfacing means, such as a keyboard, mouse, and display, input/outputports, network interface, and non-volatile storage, and execute softwareprograms structured into routines, functions, and modules for executionon the various systems. In addition, other configurations ofcomputational resources, whether provided as a dedicated system orarranged in client-server or peer-to-peer topologies, and includingunitary or distributed processing, communications, storage, and userinterfacing, are possible.

The detailed steps performed as part of the methodology described suprawith reference to FIG. 1 will now be described.

Obtain Time Series Irradiance Data

The first step is to obtain time series irradiance data fromrepresentative locations. This data can be obtained from ground-basedweather stations, existing photovoltaic systems, a satellite network, orsome combination sources, as well as from other sources. The solarirradiance data is collected from several sample locations across thegeographic region that encompasses the photovoltaic fleet.

Direct irradiance data can be obtained by collecting weather data fromground-based monitoring systems. FIG. 3 is a graph depicting, by way ofexample, ten hours of time series irradiance data collected from aground-based weather station with 10-second resolution, that is, thetime interval equals ten seconds. In the graph, the blue line 32 is themeasured horizontal irradiance and the black line 31 is the calculatedclear sky horizontal irradiance for the location of the weather station.

Irradiance data can also be inferred from select photovoltaic systemsusing their electrical power output measurements. A performance modelfor each photovoltaic system is first identified, and the input solarirradiance corresponding to the power output is determined.

Finally, satellite-based irradiance data can also be used. As satelliteimagery data is pixel-based, the data for the geographic region isprovided as a set of pixels, which span across the region andencompassing the photovoltaic fleet.

Calculate Irradiance Statistics

The time series irradiance data for each location is then converted intotime series clearness index data, which is then used to calculateirradiance statistics, as described infra.

Clearness Index (Kt)

The clearness index (Kt) is calculated for each observation in the dataset. In the case of an irradiance data set, the clearness index isdetermined by dividing the measured global horizontal irradiance by theclear sky global horizontal irradiance, which may be obtained from anyof a variety of analytical methods. FIG. 4 is a graph depicting, by wayof example, the clearness index that corresponds to the irradiance datapresented in FIG. 3 . Calculation of the clearness index as describedherein is also generally applicable to other expressions of irradianceand cloudy conditions, including global horizontal and direct normalirradiance.

Change in Clearness index (ΔKt)

The change in clearness index (ΔKt) over a time increment of Δt is thedifference between the clearness index starting at the beginning of atime increment t and the clearness index starting at the beginning of atime increment t, plus a time increment Δt. FIG. 5 is a graph depicting,by way of example, the change in clearness index that corresponds to theclearness index presented in FIG. 4 .

Time Period

The time series data set is next divided into time periods, forinstance, from five to sixty minutes, over which statisticalcalculations are performed. The determination of time period is selecteddepending upon the end use of the power output data and the timeresolution of the input data. For example, if fleet variabilitystatistics are to be used to schedule regulation reserves on a 30-minutebasis, the time period could be selected as 30 minutes. The time periodmust be long enough to contain a sufficient number of sampleobservations, as defined by the data time interval, yet be short enoughto be usable in the application of interest. An empirical investigationmay be required to determine the optimal time period as appropriate.

Fundamental Statistics

Table 1 lists the irradiance statistics calculated from time series datafor each time period at each location in the geographic region. Notethat time period and location subscripts are not included for eachstatistic for purposes of notational simplicity.

TABLE 1 Statistic Variable Mean clearness index μ_(Kt) Varianceclearness index σ_(Kt) ² Mean clearness index change μ_(ΔKt) Varianceclearness index change σ_(ΔKt) ²

Table 2 lists sample clearness index time series data and associatedirradiance statistics over five-minute time periods. The data is basedon time series clearness index data that has a one-minute time interval.The analysis was performed over a five-minute time period. Note that theclearness index at 12:06 is only used to calculate the clearness indexchange and not to calculate the irradiance statistics.

TABLE 2 Clearness index Clearness index (Kt) Change (ΔKt) 12:00 50% 40%12:01 90%  0% 12:02 90% −80%  12:03 10%  0% 12:04 10% 80% 12:05 90%−40%  12:06 50% Mean (μ) 57%  0% Variance (σ²) 13% 27%

The mean clearness index change equals the first clearness index in thesucceeding time period, minus the first clearness index in the currenttime period divided by the number of time intervals in the time period.The mean clearness index change equals zero when these two values arethe same. The mean is small when there are a sufficient number of timeintervals. Furthermore, the mean is small relative to the clearnessindex change variance. To simplify the analysis, the mean clearnessindex change is assumed to equal zero for all time periods

.FIG. 6 is a graph depicting, by way of example, the irradiancestatistics that correspond to the clearness index in FIG. 4 and thechange in clearness index in FIG. 5 using a half-hour hour time period.Note that FIG. 6 presents the standard deviations, determined as thesquare root of the variance, rather than the variances, to present thestandard deviations in terms that are comparable to the mean.

Calculate Fleet Irradiance Statistics

Irradiance statistics were calculated in the previous section for thedata stream at each sample location in the geographic region. Themeaning of these statistics, however, depends upon the data source.Irradiance statistics calculated from ground-based weather station datarepresent results for a specific geographical location as pointstatistics. Irradiance statistics calculated from satellite datarepresent results for a region as area statistics. For example, if asatellite pixel corresponds to a one square kilometer grid, then theresults represent the irradiance statistics across a physical area onekilometer square.

Average irradiance statistics across the photovoltaic fleet region are acritical part of the methodology described herein. This section presentsthe steps to combine the statistical results for individual locationsand calculate average irradiance statistics for the region as a whole.The steps differ depending upon whether point statistics or areastatistics are used.

Irradiance statistics derived from ground-based sources simply need tobe averaged to form the average irradiance statistics across thephotovoltaic fleet region. Irradiance statistics from satellite sourcesare first converted from irradiance statistics for an area intoirradiance statistics for an average point within the pixel. The averagepoint statistics are then averaged across all satellite pixels todetermine the average across the photovoltaic fleet region.

Mean Clearness Index (μ _(Kt) ) and Mean Change in Clearness Index (μ_(ΔKt) )

The mean clearness index should be averaged no matter what input datasource is used, whether ground, satellite, or photovoltaic systemoriginated data. If there are N locations, then the average clearnessindex across the photovoltaic fleet region is calculated as follows.

$\begin{matrix}{\mu_{\overset{\_}{Kt}} = {\sum\limits_{i = 1}^{N}\frac{\mu_{{Kt}_{i}}}{N}}} & (1)\end{matrix}$

The mean change in clearness index for any period is assumed to be zero.As a result, the mean change in clearness index for the region is alsozero.

μ _(ΔKt) =0  (2)

Convert Area Variance to Point Variance

The following calculations are required if satellite data is used as thesource of irradiance data. Satellite observations represent valuesaveraged across the area of the pixel, rather than single pointobservations. The clearness index derived from this data (Kt^(Area)) maytherefore be considered an average of many individual pointmeasurements.

$\begin{matrix}{{Kt}^{Area} = {{\sum}_{i = 1}^{N}\frac{{Kt}^{i}}{N}}} & (3)\end{matrix}$

As a result, the variance of the area clearness index based on satellitedata can be expressed as the variance of the average clearness indexesacross all locations within the satellite pixel.

$\begin{matrix}{\sigma_{{Kt} - {Area}}^{2} = {{{VAR}\lbrack {Kt}^{Area} \rbrack} = {{VAR}\lbrack {\sum\limits_{i = 1}^{N}\frac{{Kt}^{i}}{N}} \rbrack}}} & (4)\end{matrix}$

The variance of a sum, however, equals the sum of the covariance matrix.

$\begin{matrix}{\sigma_{{Kt} - {Area}}^{2} = {( \frac{1}{N^{2}} ){\sum\limits_{i = 1}^{N}{\sum\limits_{j = 1}^{N}{{COV}\lbrack {{Kt}^{i},{Kt}^{j}} \rbrack}}}}} & (5)\end{matrix}$

Let ρ^(Kt) ^(i) ^(,Kt) ^(j) represents the correlation coefficientbetween the clearness index at location i and location j within thesatellite pixel. By definition of correlation coefficient,COV[Kt^(i),Kt^(j)]=σ_(Kt) ^(i)σ_(Kt) ^(j)ρ^(Kt) ^(i) ^(,Kt) ^(j) .Furthermore, since the objective is to determine the average pointvariance across the satellite pixel, the standard deviation at any pointwithin the satellite pixel can be assumed to be the same and equalsσ_(Kt), which means that σ_(Kt) ^(i)σ_(Kt) ^(j)=σ_(KT) ² for alllocation pairs. As a result, COV [Kt^(i), Kt^(j)]=σ_(Kt) ²ρ^(Kt) ^(i)^(,Kt) ^(j) .Substituting this result into Equation (5) and simplify.

$\begin{matrix}{\sigma_{{Kt} - {Area}}^{2} = {{\sigma_{Kt}^{2}( \frac{1}{N^{2}} )}{\sum\limits_{i = 1}^{N}{\sum\limits_{j = 1}^{N}\rho^{{Kt}^{i},{Kt}^{j}}}}}} & (6)\end{matrix}$

Suppose that data was available to calculate the correlation coefficientin Equation (6). The computational effort required to perform a doublesummation for many points can be quite large and computationallyresource intensive. For example, a satellite pixel representing a onesquare kilometer area contains one million square meter increments. Withone million increments, Equation (6) would require one trillioncalculations to compute.

The calculation can be simplified by conversion into a continuousprobability density function of distances between location pairs acrossthe pixel and the correlation coefficient for that given distance, asfurther described infra. Thus, the irradiance statistics for a specificsatellite pixel, that is, an area statistic, rather than a pointstatistic, can be converted into the irradiance statistics at an averagepoint within that pixel by dividing by a “Area” term (A), whichcorresponds to the area of the satellite pixel. Furthermore, theprobability density function and correlation coefficient functions aregenerally assumed to be the same for all pixels within the fleet region,making the value of A constant for all pixels and reducing thecomputational burden further. Details as to how to calculate A are alsofurther described infra.

$\begin{matrix}{\sigma_{Kt}^{2} = \frac{\sigma_{{Kt} - {Area}}^{2}}{A_{Kt}^{{Satellite}{Pixel}}}} & (7)\end{matrix}$ where: $\begin{matrix}{A_{Kt}^{{Satellite}{Pixel}} = {( \frac{1}{N^{2}} ){\sum\limits_{i = 1}^{N}{\sum\limits_{j = 1}^{N}\rho^{i,j}}}}} & (8)\end{matrix}$

Likewise, the change in clearness index variance across the satelliteregion can also be converted to an average point estimate using asimilar conversion factor, A_(ΔKt) ^(Area).

$\begin{matrix}{\sigma_{\Delta{Kt}}^{2} = \frac{\sigma_{\Delta{Kt} - {Area}}^{2}}{A_{\Delta{Kt}}^{{Satellite}{Pixel}}}} & (9)\end{matrix}$

Variance of Clearness Index

$( {\sigma\frac{2}{Kt}} )$

And Variance of Change in Clearness Index

$( {\sigma\frac{2}{\Delta{Kt}}} )$

At this point, the point statistics (σ_(Kt) ² and σ_(ΔKt) ²) have beendetermined for each of several representative locations within the fleetregion. These values may have been obtained from either ground-basedpoint data or by converting satellite data from area into pointstatistics. If the fleet region is small, the variances calculated ateach location i can be averaged to determine the average point varianceacross the fleet region. If there are N locations, then average varianceof the clearness index across the photovoltaic fleet region iscalculated as follows.

$\begin{matrix}{\sigma_{\overset{\_}{Kt}}^{2} = {\sum\limits_{i = 1}^{N}\frac{\sigma_{{Kt}_{i}}^{2}}{N}}} & (10)\end{matrix}$

Likewise, the variance of the clearness index change is calculated asfollows.

$\begin{matrix}{\sigma_{\overset{\_}{\Delta{Kt}}}^{2} = {\sum\limits_{i = 1}^{N}\frac{\sigma_{\Delta{Kt}}^{2}}{N}}} & (11)\end{matrix}$

Calculate Fleet Power Statistics

The next step is to calculate photovoltaic fleet power statistics usingthe fleet irradiance statistics, as determined supra, and physicalphotovoltaic fleet configuration data. These fleet power statistics arederived from the irradiance statistics and have the same time period.

The critical photovoltaic fleet performance statistics that are ofinterest are the mean fleet power, the variance of the fleet power, andthe variance of the change in fleet power over the desired time period.As in the case of irradiance statistics, the mean change in fleet poweris assumed to be zero.

Photovoltaic System Power for Single System at Time t

Photovoltaic system power output (kW) is approximately linearly relatedto the AC-rating of the photovoltaic system (R in units of kW_(AC))times plane-of-array irradiance. Plane-of-array irradiance can berepresented by the clearness index over the photovoltaic system (KtPV)times the clear sky global horizontal irradiance times an orientationfactor (O), which both converts global horizontal irradiance toplane-of-array irradiance and has an embedded factor that convertsirradiance from Watts/m² to kW output/kW of rating. Thus, at a specificpoint in time (t), the power output for a single photovoltaic system (n)equals:

P _(t) ^(n) =R ^(n) O _(t) ^(n)KtPV_(t) ^(n) I _(t) ^(Clear,n)  (12)

The change in power equals the difference in power at two differentpoints in time.

ΔP _(t,Δt) ^(n) =R ^(n) O _(t+Δt) ^(n)KtPV_(t+Δt) ^(n) I _(t+Δt)^(Clear,n) −R ^(n) O _(t) ^(n)KtPV_(t) ^(n) I _(t) ^(Clear,n)  (13)

The rating is constant, and over a short time interval, the two clearsky plane-of-array irradiances are approximately the same (O_(t+Δt)^(n)≈R^(n)O_(t) ^(n)I_(t) ^(Clear,n)ΔKtPV_(t) ^(n)) so that the threeterms can be factored out and the change in the clearness index remains.

ΔP _(t,Δt) ^(n) ≈R ^(n) O _(t) ^(n) I _(t) ^(Clear,n)ΔKtPV_(t)^(n)  (14)

Time Series Photovoltaic Power for Single System

P^(n) is a random variable that summarizes the power for a singlephotovoltaic system n over a set of times for a given time interval andset of time periods. ΔP^(n) is a random variable that summarizes thechange in power over the same set of times.

Mean Fleet Power (μ_(p))

The mean power for the fleet of photovoltaic systems over the timeperiod equals the expected value of the sum of the power output from allof the photovoltaic systems in the fleet.

$\begin{matrix}{\mu_{P} = {E\lbrack {\sum\limits_{n = 1}^{N}{R^{n}O^{n}{KtPV}^{n}I^{{Clear},n}}} \rbrack}} & (15)\end{matrix}$

If the time period is short and the region small, the clear skyirradiance does not change much and can be factored out of theexpectation.

$\begin{matrix}{\mu_{P} = {\mu_{I}^{Clear}{E\lbrack {\sum\limits_{n = 1}^{N}{R^{n}O^{n}KtPV^{n}}} \rbrack}}} & (16)\end{matrix}$

Again, if the time period is short and the region small, the clearnessindex can be averaged across the photovoltaic fleet region and any givenorientation factor can be assumed to be a constant within the timeperiod. The result is that:

μ_(p) =R ^(Adj.Fleet)μ_(I) _(clear) μ _(Kt)   (17)

where μ_(I) _(Clear) is calculated, μ _(Kt) is taken from Equation (1)and:

$\begin{matrix}{R^{{Adj}.{Fleet}} = {\sum\limits_{n = 1}^{N}{R^{n}O^{n}}}} & (18)\end{matrix}$

This value can also be expressed as the average power during clear skyconditions times the average clearness index across the region.

μ_(p)=μ_(p) _(Clear) μ _(Kt)   (19)

Variance of Fleet Power (σ_(p) ²)

The variance of the power from the photovoltaic fleet equals:

$\begin{matrix}{\sigma_{P}^{2} = {{VAR}\lbrack {\sum\limits_{n = 1}^{N}{R^{n}O^{n}KtPV^{n}I^{{Clear},n}}} \rbrack}} & (20)\end{matrix}$

If the clear sky irradiance is the same for all systems, which will bethe case when the region is small and the time period is short, then:

$\begin{matrix}{\sigma_{P}^{2} = {{VAR}\lbrack {I^{Clear}{\sum\limits_{n = 1}^{N}{R^{n}O^{n}KtPV^{n}}}} \rbrack}} & (21)\end{matrix}$

The variance of a product of two independent random variables X, Y, thatis, VAR[XY]) equals E[X]²VAR[Y]+E[Y]²VAR[X]+VAR[X]VAR[Y]. If the Xrandom variable has a large mean and small variance relative to theother terms, then VAR[XY]≈E[X]²VAR[Y]. Thus, the clear sky irradiancecan be factored out of Equation (21) and can be written as:

$\begin{matrix}{\sigma_{P}^{2} = {( \mu_{I}^{Clear} )^{2}{{VAR}\lbrack {\sum\limits_{n = 1}^{N}{R^{n}KtPV^{n}O^{n}}} \rbrack}}} & (22)\end{matrix}$

The variance of a sum equals the sum of the covariance matrix.

$\begin{matrix}{\sigma_{P}^{2} = {( \mu_{I}^{Clear} )^{2}( {\sum\limits_{i = 1}^{N}{\sum\limits_{j = 1}^{N}{{COV}\lbrack {{R^{i}KtPV^{i}O^{i}},{R^{j}KtPV^{j}O^{j}}} \rbrack}}} )}} & (23)\end{matrix}$

In addition, over a short time period, the factor to convert from clearsky GHI to clear sky POA does not vary much and becomes a constant. Allfour variables can be factored out of the covariance equation.

$\begin{matrix}{\sigma_{P}^{2} = {( \mu_{I}^{Clear} )^{2}( {\sum\limits_{i = 1}^{N}{\sum\limits_{j = 1}^{N}{( {R^{i}O^{i}} )( {R^{j}O^{j}} ){{COV}\lbrack {{KtPV}^{i},{KtPV^{j}}} \rbrack}}}} )}} & (24)\end{matrix}$

For any i and j,

${{COV}\lbrack {{KtPV}^{i},{KtPV}^{j}} \rbrack} = {\sqrt{\sigma_{{KtPV}^{i}}^{2}\sigma_{{KtPV}^{j}}^{2}}{\rho^{{Kt}^{i},{Kt}^{j}}.}}$$\begin{matrix}{\sigma_{P}^{2} = {( \mu_{I}^{Clear} )^{2}( {\sum\limits_{i = 1}^{N}{\sum\limits_{j = 1}^{N}{( {R^{i}O^{i}} )( {R^{j}O^{j}} )\sqrt{\sigma_{{KtPV}^{i}}^{2}\sigma_{{KtPV}^{j}}^{2}}\rho^{{Kt}^{i},{Kt}^{j}}}}} )}} & (25)\end{matrix}$

As discussed supra, the variance of the satellite data required aconversion from the satellite area, that is, the area covered by apixel, to an average point within the satellite area. In the same way,assuming a uniform clearness index across the region of the photovoltaicplant, the variance of the clearness index across a region the size ofthe photovoltaic plant within the fleet also needs to be adjusted. Thesame approach that was used to adjust the satellite clearness index canbe used to adjust the photovoltaic clearness index. Thus, each varianceneeds to be adjusted to reflect the area that the i^(th) photovoltaicplant covers.

$\begin{matrix}{\sigma_{{KtPV}^{i}}^{2} = {A_{Kt}^{i}\sigma\frac{2}{Kt}}} & (26)\end{matrix}$

Substituting and then factoring the clearness index variance given theassumption that the average variance is constant across the regionyields:

$\begin{matrix}{\sigma_{P}^{2} = {( {R^{{Adj}.{Fleet}}\mu_{I}^{Clear}} )^{2}P^{Kt}\sigma\frac{2}{Kt}}} & (27)\end{matrix}$

where the correlation matrix equals:

$\begin{matrix}{P^{Kt} = \frac{{\sum}_{i = 1}^{N}{\sum}_{j = 1}^{N}( {R^{i}O^{i}A_{Kt}^{i}} )( {R^{j}O^{j}A_{Kt}^{j}} )\rho^{{Kt}^{i},{Kt}^{j}}}{( {{\sum}_{n = 1}^{N}R^{n}O^{n}} )^{2}}} & (28)\end{matrix}$

R^(Adj.Fleet)μ_(I) _(Clear) in Equation (27) can be written as the powerproduced by the photovoltaic fleet under clear sky conditions, that is:

$\begin{matrix}{\sigma_{P}^{2} = {\mu_{P}^{{Clear}^{2}}P^{Kt}\sigma\frac{2}{Kt}}} & (29)\end{matrix}$

If the region is large and the clearness index mean or variances varysubstantially across the region, then the simplifications may not beable to be applied. Notwithstanding, if the simplification isinapplicable, the systems are likely located far enough away from eachother, so as to be independent. In that case, the correlationcoefficients between plants in different regions would be zero, so mostof the terms in the summation are also zero and an inter-regionalsimplification can be made. The variance and mean then become theweighted average values based on regional photovoltaic capacity andorientation.

DISCUSSION

In Equation (28), the correlation matrix term embeds the effect ofintra-plant and inter-plant geographic diversification. The area-relatedterms (A) inside the summations reflect the intra-plant power smoothingthat takes place in a large plant and may be calculated using thesimplified relationship, as further discussed supra. These terms arethen weighted by the effective plant output at the time, that is, therating adjusted for orientation. The multiplication of these terms withthe correlation coefficients reflects the inter-plant smoothing due tothe separation of photovoltaic systems from one another.

Variance of Change in Fleet Power (σ_(ΔP) ²)

A similar approach can be used to show that the variance of the changein power equals:

$\begin{matrix}{\sigma_{\Delta P}^{2} = {\mu_{P}^{{Clear}^{2}}P^{\Delta{Kt}}\sigma\frac{2}{\Delta{Kt}}}} & (30)\end{matrix}$ where: $\begin{matrix}{P^{\Delta{Kt}} = \frac{{\sum}_{i = 1}^{N}{\sum}_{j = 1}^{N}( {R^{i}O^{i}A_{\Delta{Kt}}^{i}} )( {R^{j}O^{j}A_{\Delta{Kt}}^{j}} )\rho^{{\Delta{Kt}^{i}},{\Delta{Kt}^{j}}}}{( {{\sum}_{n = 1}^{N}R^{n}O^{n}} )^{2}}} & (31)\end{matrix}$

Variance of Change in Fleet Power as Decreasing Function of Distance

The determinations of Equations (5), (6), (8), (23), (24), (28), (30),and (31) each require solving a covariance matrix or some derivative ofthe covariance matrix, which becomes increasingly computationallyintensive at an exponential or near-exponential rate as the network ofpoints representing each system within the photovoltaic fleet grows. Forexample, a network with 10,000 photovoltaic systems would require thecomputation of a correlation coefficient matrix with 100 millioncalculations. As well, in some applications, the computation must becompleted frequently and possibly over a near-term time window toprovide fleet-wide power output forecasting to planners and operators.The computing of 100 million covariance solutions, though, can requirean inordinate amount of computational resource expenditure in terms ofprocessing cycles, network bandwidth and storage, plus significant timefor completion, making frequent calculation effectively impracticable.

To illustrate the computational burden associated with solving acovariance matrix, consider an example of calculating the variability ofthe power output of a fleet of N photovoltaic systems. Let the poweroutput associated with each individual photovoltaic system i berepresented by the random variable P^(i). The variance of the fleetFleetVariance is defined as follows:

$\begin{matrix}{{{Fleet}{Variance}} = {{VAR}\lbrack {\sum\limits_{i = 1}^{N}P^{i}} \rbrack}} & (32)\end{matrix}$

In general, the variance of the sum of random variables can be expressedas the sum of the covariance matrix, provided that the variables arecorrelated. Thus, Equation (32) can be rewritten as:

$\begin{matrix}{{{VAR}\lbrack {\sum\limits_{i = 1}^{N}P^{i}} \rbrack} = {\underset{i = 1}{\overset{N}{\sum}}{\sum\limits_{j = 1}^{N}{{COV}\lbrack {P^{i},P^{j}} \rbrack}}}} & (33)\end{matrix}$

Solving the covariance matrix in Equation (33) requires N² calculations,which represents an exponential computational burden. As asimplification, the computational burden can be reduced first, byrecognizing that the covariance for a location and itself merely equalsthe variance of the location, and second, by noting that the covariancecalculation is order independent, that is, the covariance betweenlocations A and B equals the covariance between locations B and A. Thus,Equation (33) can be rewritten as:

$\begin{matrix}{{{VAR}\lbrack {\sum\limits_{i = 1}^{N}P^{i}} \rbrack} = {{\sum\limits_{i = 1}^{N}\sigma_{P^{i}}^{2}} + {2{\sum\limits_{i = 1}^{N - 1}{\sum\limits_{j = {i + 1}}^{N}{{COV}\lbrack {P^{i},P^{j}} \rbrack}}}}}} & (34)\end{matrix}$

Equation (34) reduces the number of calculations by slightly less thanhalf from N² to N[(N−1)/2+1]. This approach, however, is stillexponentially related to the number of locations in the network and cantherefore become intractable.

Another way to express each term in the covariance matrix is using thestandard deviations and Pearson's correlation coefficient. The Pearson'scorrelation coefficient between two variables is defined as thecovariance of the two variables divided by the product of their standarddeviations. Thus, Equation (34) can be rewritten as:

$\begin{matrix}{{{VAR}\lbrack {\sum\limits_{i = 1}^{N}P^{i}} \rbrack} = {\sum\limits_{i = 1}^{N}{\sum\limits_{j = 1}^{N}{\rho^{P^{i},P^{j}}\sigma_{P^{i}}\sigma_{P^{j}}}}}} & (35)\end{matrix}$

However, Equation (35) still exhibits the same computational complexityas Equation (34) and does not substantially alleviate the computationalload.

Skipping ahead, FIGS. 30A-30F are graphs depicting, by way of example,the measured and predicted weighted average correlation coefficients foreach pair of locations versus distance. FIGS. 31A-31F are graphsdepicting, by way of example, the same information as depicted in FIGS.30A-30F versus temporal distance, based on the assumption that cloudspeed was six meters per second. The upper line and dots appearing inclose proximity to the upper line present the clearness index and thelower line and dots appearing in close proximity to the lower linepresent the change in clearness index for time intervals from 10 secondsto 5 minutes. The symbols are the measured results and the lines are thepredicted results. FIGS. 30A-30F and 31A-31F suggest that thecorrelation coefficient for sky clearness between two locations, whichis the critical variable in determining photovoltaic power production,is a decreasing function of the distance between the two locations. Thecorrelation coefficient is equal to 1.0 when the two systems are locatednext to each other, while the correlation coefficient approaches zero asthe distance increases, which implies that the covariance between thetwo locations beyond some distance is equal to zero, that is, the twolocations are not correlated.

The computational burden can be reduced in at least two ways. First,where pairs of photovoltaic systems are located too far away from eachother to be statistically correlated, the correlation coefficients inthe matrix for that pair of photovoltaic systems are effectively equalto zero. Consequently, the double summation portion of the variancecalculation can be simplified to eliminate zero values based on distancebetween photovoltaic plant locations. Second, once the simplificationhas been made, rather than calculating the entire covariance matrixon-the-fly for every time period, the matrix can be calculated once atthe beginning of the analysis for a variety of cloud speed conditions,after which subsequent analyses would simply perform a lookup of theappropriate pre-calculated covariance value. The zero valuesimplification of the correlation coefficient matrix will now bediscussed in detail.

As a heuristical simplification, the variance of change in fleet powercan be computed as a function of decreasing distance. When irradiancedata is obtained from a satellite imagery source, irradiance statisticsmust first be converted from irradiance statistics for an area intoirradiance statistics for an average point within a pixel in thesatellite imagery. The average point statistics are then averaged acrossall satellite pixels to determine the average across the wholephotovoltaic fleet region. FIG. 7 is a flow diagram showing a functionfor determining variance for use with the method 10 of FIG. 1 . Thefunction 40 calculates the variance of the average point statisticsacross all satellite pixels for the bounded area upon which aphotovoltaic fleet either is (or can be) situated. Each point within thebounded area represents the location of a photovoltaic plant that ispart of the fleet.

The function 40 is described as a recursive procedure, but could also beequivalently expressed using an iterative loop or other form ofinstruction sequencing that allows values to be sequentially evaluated.Additionally, for convenience, an identification number from an orderedlist can be assigned to each point, and each point is then sequentiallyselected, processed and removed from the ordered list upon completion ofevaluation. Alternatively, each point can be selected such that onlythose points that have not yet been evaluated are picked (step 41). Arecursive exit condition is defined, such that if all points have beenevaluated (step 42), the function immediately exits.

Otherwise, each point is evaluated (step 42), as follows. First, a zerocorrelation value is determined (step 43). The zero correlation value isa value for the correlation coefficients of a covariance matrix, suchthat, the correlation coefficients for a given pair of points that areequal to or less than (or, alternatively, greater than) the zerocorrelation value can be omitted from the matrix with essentially noeffect on the total covariance. The zero correlation value can be usedas a form of filter on correlation coefficients in at least two ways.The zero correlation value can be set to a near-zero value.

In one embodiment where the variance between the points within a boundedarea is calculated as a bounded area variance using a continuousprobability density function, the zero correlation value is a thresholdvalue against which correlation coefficients are compared. In a furtherembodiment where the variance between the points within a bounded areais calculated as an average point variance, a zero correlation distanceis found as a function of the zero correlation value (step 44). The zerocorrelation distance is the distance beyond which there is effectivelyno correlation between the photovoltaic system output (or the change inthe photovoltaic system output) for a given pair of points. The zerocorrelation distance can be calculated, for instance, by settingEquation (64) (for power) or Equation (65) (for the change in power), asfurther discussed infra, equal to the zero correlation value and solvingfor distance. These equations provide that the correlation is a functionof distance, cloud speed, and time interval. If cloud speed variesacross the locations, then a unique zero correlation distance can becalculated for each point. In a further embodiment, there is one zerocorrelation distance for all points if cloud speed is the same acrossall locations. In a still further embodiment, a maximum (or minimum)zero correlation distance across the locations can be determined byselecting the point with the slowest (or fastest) cloud speed. Stillother ways of obtaining the zero correlation distance are possible,including evaluation of equations that express correlation as a functionof distance (and possibly other parameters) by which the equation is setto equal the zero correlation value and solved for distance.

The chosen point is paired with each of the other points that have notalready been evaluated and, if applicable, that are located within thezero correlation distance of the chosen point (step 45). In oneembodiment, the set of points located within the zero correlationdistance can be logically represented as falling within a grid orcorrelation region centered on the chosen point. The zero correlationdistance is first converted (from meters) into degrees and the latitudeand longitude coordinates for the chosen point are found. Thecorrelation region is then defined as a rectangular or square region,such that Longitude−Zero Correlation Degrees≤Longitude≤Longitude+ZeroCorrelation Degrees and Latitude−Zero CorrelationDegrees≤Latitude≤Latitude+Zero Correlation Degrees. In a furtherembodiment, the correlation region is constructed as a circular regioncentered around the chosen point. This option, however, requirescalculating the distance between the chosen point and all other possiblepoints.

Each of the pairings of chosen point-to-a point yet to be evaluated areiteratively processed (step 46) as follows. A correlation coefficientfor the point pairing is calculated (step 47). In one embodiment wherethe variance is calculated as a bounded area variance, the covariance isonly calculated (step 49) and added to the variance of the areaclearness index (step 50) if the correlation coefficient is greater thanthe zero correlation value (step 48). In a further embodiment where thevariance is calculated as an average point variance, the covariance issimply calculated (step 49) and added to the variance of the areaclearness index (step 50). Processing continues with the next pointpairing (step 51). Finally, the function 40 is recursively called toevaluate the next point, after which the variance is returned.

The variance heuristic determination can be illustrated through twoexamples. FIGS. 8 and 9 are block diagrams respectively showing, by wayof example, nine evenly-spaced points within a four-by-four correlationregion and 16 evenly-spaced points within a three-by-three correlationregion for evaluation by the function of FIG. 7 . Referring first toFIG. 8 , suppose that there are nine photovoltaic system locations,which are evenly spaced in a square three-by-three region. Evaluationproceeds row-wise, left-to-right, top-to-bottom, from the upperleft-hand corner, and the chosen location is labeled with anidentification number. Within each evaluative step, the black squarewith white lettering represents the chosen point and the heavy blackborder represents the corresponding correlation region. The dark graysquares are the locations for which correlation is non-zero and thelight gray squares are the locations for which correlation is zero. Thenumber of correlation coefficients to be calculated equals the sum ofthe number of dark gray boxes, with 20 correlation correlationscalculated here. Note that while this example presents the results in aparticular order, the approach does not require the locations to beconsidered in any particular order. Referring next to FIG. 9 , supposethat there are now 16 photovoltaic system locations, which are evenlyspaced in the four-by-four region. As before, evaluation proceedsrow-wise, left-to-right, top-to-bottom, from the upper left-hand corner,and the chosen location is labeled with an identification number.However, in this example, there are 42 correlation coefficientcalculations.

The number of point pairing combinations to be calculated for differentnumbers of points and sizes of correlation regions can be determined asa function of the number of locations and the correlation region size.Due to edge effects, however, determination can be complicated and asimpler approach is to simply determine an upper bound on the number ofcorrelations to be calculated. Assuming equal spacing, the upper bound Ccan be determined as:

$\begin{matrix}{C = \frac{N*( {{{Correlation}{Region}} - 1} )}{2}} & (36)\end{matrix}$

where N is the number of points within the bounded area and CorrelationRegion is the number of equal-sized divisions of the bounded area.

The upper bound can be used to illustrate the reduction of the problemspace from exponential to linear. FIG. 10 is a graph depicting, by wayof example, the number of calculations required when determiningvariance using three different approaches. The x-axis represents thenumber of photovoltaic plant locations (points) within the boundedregion. The y-axis represents the upper bound on the number ofcorrelation calculations required, as determined using Equation (35).Assume, for instance, that a correlation region includes nine divisionsand that the number of possible points ranges up to 100. The totalpossible correlations required using correlation coefficient matrixcomputations without simplification is as high as 10,000 computations,whilst the total possible correlations required using the simplificationafforded by standard deviations and Pearson's correlation coefficient,per Equation (35), is as high as 5,000 computations. By comparison, theheuristical of determining the variance of change in fleet power as afunction of decreasing distance approach requires a maximum of 400correlations calculations, which represents a drastic reduction incomputational burden without cognizable loss of accuracy in variance.

Time Lag Correlation Coefficient

The next step is to adjust the photovoltaic fleet power statistics fromthe input time interval to the desired output time interval. Forexample, the time series data may have been collected and stored every60 seconds. The user of the results, however, may want to havephotovoltaic fleet power statistics at a 10-second rate. This adjustmentis made using the time lag correlation coefficient.

The time lag correlation coefficient reflects the relationship betweenfleet power and that same fleet power starting one time interval (Δt)later. Specifically, the time lag correlation coefficient is defined asfollows:

$\begin{matrix}{\rho^{P,P^{\Delta t}} = \frac{{COV}\lbrack {P,P^{\Delta t}} \rbrack}{\sqrt{\sigma_{P}^{2}\sigma_{P^{\Delta t}}^{2}}}} & (37)\end{matrix}$

The assumption that the mean clearness index change equals zero impliesthat σ_(pΔt)=σ_(p) ². Given a non-zero variance of power, thisassumption can also be used to show that

$\frac{{COV}\lbrack {P,P^{\Delta t}} \rbrack}{\sigma_{P}^{2}} = {1 - {\frac{\sigma_{\Delta P}^{2}}{2\sigma_{P}^{2}}.}}$

Therefore:

$\begin{matrix}{\rho^{P,P^{\Delta t}} = {1 - \frac{\sigma_{\Delta P}^{2}}{2\sigma_{P}^{2}}}} & (38)\end{matrix}$

This relationship illustrates how the time lag correlation coefficientfor the time interval associated with the data collection rate iscompletely defined in terms of fleet power statistics alreadycalculated. A more detailed derivation is described infra.

Equation (38) can be stated completely in terms of the photovoltaicfleet configuration and the fleet region clearness index statistics bysubstituting Equations (29) and (30). Specifically, the time lagcorrelation coefficient can be stated entirely in terms of photovoltaicfleet configuration, the variance of the clearness index, and thevariance of the change in the clearness index associated with the timeincrement of the input data.

$\begin{matrix}{\rho^{P,P^{\Delta t}} = {1 - \frac{P^{\Delta{Kt}}\sigma_{\overset{\_}{\Delta{Kt}}}^{2}}{2P^{Kt}\overset{\_}{\sigma_{\overset{\_}{Kt}}^{2}}}}} & (39)\end{matrix}$

Generate High-Speed Time Series Photovoltaic Fleet Power

The final step is to generate high-speed time series photovoltaic fleetpower data based on irradiance statistics, photovoltaic fleetconfiguration, and the time lag correlation coefficient. This step is toconstruct time series photovoltaic fleet production from statisticalmeasures over the desired time period, for instance, at half-hour outputintervals.

A joint probability distribution function is required for this step. Thebivariate probability density function of two unit normal randomvariables (X and Y) with a correlation coefficient of ρ equals:

$\begin{matrix}{{f( {x,y} )} = {\frac{1}{2\pi\sqrt{1 - \rho^{2}}}{\exp\lbrack {- \frac{( {x^{2} + y^{2} - {2\rho{xy}}} )}{2( {1 - \rho^{2}} )}} \rbrack}}} & (40)\end{matrix}$

The single variable probability density function for a unit normalrandom variable X alone is

$(x) = {\frac{1}{\sqrt{2\pi}}\exp{( {- \frac{x^{2}}{2}} ).}}$

In addition, a conditional distribution for y can be calculated based ona known x by dividing the bivariate probability density function by thesingle variable probability density, that is,

$\begin{matrix}{{f( {y❘x} )} = {\frac{f( {x,y} )}{f(x)}.}} & (x)\end{matrix}$

Making the appropriate substitutions, the result is that the conditionaldistribution of y based on a known x equals:

$\begin{matrix}{{f( {y❘x} )} = {\frac{1}{2\pi\sqrt{1 - \rho^{2}}}{\exp\lbrack {- \frac{( {y - {\rho x}} )^{2}}{2( {1 - \rho^{2}} )}} \rbrack}}} & (41)\end{matrix}$

Define a random variable

$Z = \frac{Y - {\rho x}}{\sqrt{1 - \rho^{2}}}$

and substitute into Equation (41). The result is that the conditionalprobability of z given a known x equals:

$\begin{matrix}{{f( {z❘x} )} = {\frac{1}{\sqrt{2\pi}}\exp( {- \frac{z^{2}}{2}} )}} & (42)\end{matrix}$

The cumulative distribution function for Z can be denoted by Φ(z*),where z* represents a specific value for z. The result equals aprobability (p) that ranges between 0 (when z*=−∞) and 1 (when z*=∞).The function represents the cumulative probability that any value of zis less than z*, as determined by a computer program or value lookup.

$\begin{matrix}{p = {{\Phi( z^{*} )} = {\frac{1}{\sqrt{2\pi}}{\int_{- \infty}^{z^{*}}{\exp( {- \frac{z^{2}}{2}} ){dz}\,}}}}} & (43)\end{matrix}$

Rather than selecting z*, however, a probability p falling between 0 and1 can be selected and the corresponding z* that results in thisprobability found, which can be accomplished by taking the inverse ofthe cumulative distribution function.

Φ⁻¹(p)=z*  (44)

Substituting back for z as defined above results in:

$\begin{matrix}{{\Phi^{- 1}(p)} = \frac{y - {\rho x}}{\sqrt{1 - \rho^{2}}}} & (45)\end{matrix}$

Now, let the random variables equal

$X = \frac{P - \mu_{P}}{\sigma_{P}}$ and${Y = \frac{P^{\Delta t} - \mu_{P^{\Delta t}}}{\sigma_{P^{\Delta t}}}},$

with the correlation coefficient being the time lag correlationcoefficient between P and P^(Δt), that is, let ρ=ρ^(P,P) ^(Δt) . When Δtis small, then the mean and standard deviations for P^(Δt) areapproximately equal to the mean and standard deviation for P. Thus, Ycan be restated as

$Y \approx {\frac{P^{\Delta t} - \mu_{P}}{\sigma_{P}}.}$

Add a time subscript to all of the relevant data to represent a specificpoint in time and substitute x, y, and ρ into Equation (45).

$\begin{matrix}{{\Phi^{- 1}(p)} = \frac{( \frac{P_{t}^{\Delta t} - \mu_{P}}{\sigma_{P}} ) - {\rho^{P,P^{\Delta t}}( \frac{P_{t} - \mu_{P}}{\sigma_{P}} )}}{\sqrt{1 - \rho^{P,P^{\Delta t^{2}}}}}} & (46)\end{matrix}$

The random variable P^(Δt), however, is simply the random variable Pshifted in time by a time interval of Δt. As a result, at any given timet, P^(Δt) _(t)=P_(t+Δt). Make this substitution into Equation (46) andsolve in terms of P_(t+Δt).

P _(t+Δt)=ρ^(P.PΔt) P _(t)+(1−ρ^(P,PΔt))μ_(P)+√{square root over (σ_(P)²(1−ρ^(P,PΔt) ² ))}Φ⁻¹(p)  (47)

At any given time, photovoltaic fleet power equals photovoltaic fleetpower under clear sky conditions times the average regional clearnessindex, that is, P_(t)=P_(t) ^(Clear)Kt_(t). In addition, over a shorttime period,

$\mu_{P} \approx {P_{t}^{Clear}\mu_{\overset{\_}{Kt}}{and}{}\sigma_{P}^{2}} \approx {( P_{t}^{Clear} )^{2}P^{Kt}{\sigma_{\overset{\_}{Kt}}^{2}.}}$

Substitute these three relationships into Equation (47) and factor outphotovoltaic fleet power under clear sky conditions (P_(t) ^(Clear)) ascommon to all three terms.

$\begin{matrix}{P_{t + {\Delta t}} = {P_{t}^{Clear}\lbrack {{\rho^{P,P^{\Delta t}}Kt_{t}} + {( {1 - \rho^{P,P^{\Delta t}}} )\mu_{\overset{\_}{Kt}}} + {\sqrt{P^{Kt}{\sigma_{\overset{\_}{Kt}}^{2}( {1 - \rho^{P,P^{\Delta t^{2}}}} )}}{\Phi^{- 1}( p_{t} )}}} \rbrack}} & (48)\end{matrix}$

Equation (48) provides an iterative method to generate high-speed timeseries photovoltaic production data for a fleet of photovoltaic systems.At each time step (t+Δt), the power delivered by the fleet ofphotovoltaic systems (P_(t+Δt)) is calculated using input values fromtime step t. Thus, a time series of power outputs can be created. Theinputs include:

-   -   P_(t) ^(Clear)—photovoltaic fleet power during clear sky        conditions calculated using a photovoltaic simulation program        and clear sky irradiance.    -   Kt_(t)— average regional clearness index inferred based on P_(t)        calculated in time step t, that is, Kt_(t)=P_(t)/P_(t) ^(Clear).    -   μ _(Kt) —mean clearness index calculated using time series        irradiance data and Equation (1).

$\sigma_{\overset{\_}{Kt}}^{2}$

-   -   —variance of the clearness index calculated using time series        irradiance data and Equation (10).    -   ρ^(PPΔt)—fleet configuration as reflected in the time lag        correlation coefficient calculated using Equation (38). In turn,        Equation (38), relies upon correlation coefficients from        Equations (28) and (31). A method to obtain these correlation        coefficients by empirical means is described in        commonly-assigned U.S. Pat. Nos. 8,165,811 and 8,165,813, the        disclosure of which are incorporated by reference.    -   p^(Kt)—fleet configuration as reflected in the clearness index        correlation coefficient matrix calculated using Equation (28)        where, again, the correlation coefficients may be obtained using        the empirical results as further described infra.    -   Φ⁻¹(p_(t))—the inverse cumulative normal distribution function        based on a random variable between 0 and 1.

Generate High-Speed Time Series Photovoltaic Fleet Energy

The accuracy of photovoltaic simulation modeling is predicated upon theselection of a type of solar resource data appropriate to the form ofsimulation desired. Photovoltaic power simulation requires irradiancedata. Solar irradiance is instantaneous and should be associated with asingle observation time. The simulation should therefore return a powermeasure for the same single observation time, thereby avoiding anyconfusion that the simulation results represent power, which, likeirradiance, is also an instantaneous measure.

On the other hand, photovoltaic energy simulation requires normalizedirradiation data. Normalized irradiation is an interval measure boundedby either start and end times or by a single observation time with atime interval convention. The simulation should therefore return a powermeasure for the start and end time-bounded interval, or a singleobservation time with a description of the time convention.Alternatively, photovoltaic energy can be indirectly simulated by firstperforming photovoltaic power simulations using irradiance data andconverting the photovoltaic power simulation results into photovoltaicenergy simulation results.

Irradiance Versus Normalized Irradiation

An accurate simulation requires consistency between both the solarresource data and the photovoltaic simulation code. Simulatingphotovoltaic production is typically divided into two parts, solarirradiance data acquisition and production simulation. Photovoltaicproduction, whether for power or energy, is usually simulated using twoseparate services, one service that provides the irradiance data andanother service that performs the simulation.

Solar irradiance data can be obtained from ground-based measurements,satellite imagery, and numerical weather prediction models. Reliablesolar irradiance data, as well as simulation tools, are also availablefrom third party sources, such as the SolarAnywhere data grid webinterface, which, by default, reports irradiance data for a desiredlocation using a single observation time, and the SolarAnywherephotovoltaic system modeling service, available in the SolarAnywhereToolkit, that uses hourly resource data and user-defined physical systemattributes to simulate configuration-specific photovoltaic systemoutput. SolarAnywhere is available online (http://www.SolarAnywhere.com)through Web-based services operated by Clean Power Research, L.L.C.,Napa, CA. Other sources of the solar irradiance data are possible,including numeric weather prediction models.

By default, the SolarAnywhere service implicitly assumes that irradiancedata is being requested and translates satellite images to irradiance torepresent instantaneous weather conditions at a specific point in time.FIG. 11 is a screen shot showing, by way of example, a user interface 60of SolarAnywhere. To obtain irradiance data, the user must select alocation 61, date range 62, time resolution 63, and output format 64.The SolarAnywhere service allows users to retrieve the irradiance dataformatted as either centered on satellite measurement time or standardtop of hour, end of period integration.

Despite their names, these formats do not provide forms of normalizedirradiation data. Out of naiveté, a user could incorrectly believe thatirradiance data is equivalent to normalized irradiation data, then usethe irradiance data to simulate photovoltaic energy production, ratherthan photovoltaic power production. The centered on satellitemeasurement time format returns irradiance data that should be used forpower calculations. The standard top of hour, end of period integrationformat provides neither irradiance nor irradiation data; theSolarAnywhere service calculates the clearness index, shifts theclearness index by some number of minutes while holding the clearnessindex constant, and then multiplies the shifted clearness index by clearsky irradiance. FIGS. 12A-12B are graphs showing, by way of example, asample day of solar irradiance plotted respectively based on thecentered on satellite measurement time and standard top of hour, end ofperiod integration formats. In both graphs, the x-axes represent time ofday and the y-axes represent GHI, as data returned by the SolarAnywhereservice, Enhanced Resolution, for Jun. 1, 2013 for Napa, CA. Referringfirst to FIG. 12A, the solid line corresponds to the satellite timestamp using the centered on satellite measurement time format and thedashed line corresponds to the standard top of hour, end of periodintegration format. Referring next to FIG. 12B, the solid linecorresponds to the satellite time stamp using the centered on satellitemeasurement time format and the dashed line corresponds to the standardtop of hour, end of period integration format, minus half of a specifiedtime interval of 15 minutes to adjust for the time shift. FIGS. 12A-12Bhelp to illustrate that the fundamental satellite image pattern cannotbe replicated simply by adjusting the time stamps, once time shiftingoccurred, that is, the dashed lines cannot be lined up with the solidlines, no matter how much the time axes are shifted. On the one hand,clear sky conditions do not match if both output formats are plottedagainst observation time. On the other hand, clear sky conditions match,yet cloudy conditions are shifted if the centered on satellitemeasurement time format is plotted against observation time, while thestandard top of hour, end of period integration format is plottedagainst the center of the observation time.

Sources of Normalized Irradiation

Normalized irradiation is not always available, such as in photovoltaicplant installations where only point measurements of irradiance aresporadically collected or even entirely absent. Residential photovoltaicsystems that contribute to a power grid, yet which are geographicallyremoved from the grid's central operations, for instance, may lack solarirradiance measurement instrumentation. Notwithstanding, normalizedirradiation is necessary for accurate photovoltaic energy simulation.Normalized irradiation can be estimated over a set time period throughseveral methodologies, including assuming that normalized irradiationsimply equals irradiance, directly estimating normalized irradiation,applying linear interpolation to irradiance, applying linearinterpolation to clearness index values, and empirically derivingirradiance weights, as further described infra. Still othermethodologies of estimating normalized irradiation are possible.

By way of overview, the foregoing methodologies can be illustrated usinga sample day. FIGS. 13A-13B are graphs respectively showing, by way ofexample, a sample day of irradiance and clearness indexes. In bothgraphs, the x-axes represent time of day and the y-axes respectivelyrepresent irradiance and clearness index. Referring first to FIG. 13A,clear sky irradiance I_(t) ^(ClearSky) over a sixteen-hour period, from4:00 am to 8:00 pm, is plotted as a continuous line and the GHI isplotted as discrete dots. Clear sky irradiance I_(t) ^(ClearSky) is avalue calculated for any value of time t and can therefore berepresented as a continuous value, whereas GHI is represented asdiscrete points because those values are observed at specific points intime, such as on an hourly basis. Clear sky irradiance I_(t) ^(ClearSky)can either be measured directly or can be calculated as the product of aclearness index Kt* and clear sky irradiance I_(t) ^(ClearSky).Referring next to FIG. 13B, the clearness indexes Kt* are plotted asdiscrete dots over the same sixteen-hour period Like GHI, the clearnessindexes Kt* are represented as discrete points corresponding toobservations recorded at specific points in time. FIGS. 14A-14B aregraphs respectively showing, by way of example, two-hour periods of theirradiance and clearness indexes of the sample day of FIGS. 13A-13B. Inboth graphs, the x-axes represent time of day and the y-axesrespectively represent irradiance and clearness index. FIGS. 14A-14Bisolate the time period from 11:00 am to 13:00 pm and will be used as aset time period to illustrate the various methodologies for estimatingnormalized irradiation. In the discussion that immediately follows, theobservations in FIGS. 14A-14B at 11:00 am, 12:00 pm, and 1:00 pmcorrespond to times t⁻¹, t₀, and t₁, except as indicated to thecontrary.

The five methodologies for estimating normalized irradiation will now bedescribed in detail. In addition, the user interface 60, discussed suprawith reference to FIG. 11 , could be extended to allow users to retrievethe irradiance data in formats that include the foregoing forms ofnormalized irradiation data based on a requested or set time period, aswell as other forms of irradiance and normalized irradiation data.

Equate Irradiance to Normalized Irradiation

Conventional solar resource databases generally provide a single solarresource value for a specific observation time and lack support for theselection of either irradiance or normalized irradiation data. FIG. 15is a graph showing, by way of example, normalized irradiation equated toirradiance based on the irradiance plotted in FIG. 14A. The x-axisrepresents time of day and the y-axis represents irradiance. Normalizedirradiation is set to equal the value of the irradiance observation at12:00 pm, as indicated by the vertical dashed line. FIG. 14A helpsillustrate the widely-implemented assumption in solar resource databasesthat normalized irradiation, that is, average irradiance, and irradiancecan be treated as equivalent measures. However, this assumption producesinferior results because irradiance is a point measure that fails toreflect the passage of time.

Directly Calculate Normalized Irradiation

Normalized irradiation is analogous to the average of a set ofirradiance values consecutively measured over a set time interval andcan therefore be directly calculated. Non-normalized irradiation is toirradiance what energy is to power and can be calculated by summing thearea under the irradiance curve. Let I_(t) represent irradiance at timet, t₀ the start time, and Δt be the time interval of interest. Theirradiation between t₀ and t₀+/Δt equals:

Irradiation_(t) ₀ _(tot) ₀ _(+Δt)=∫_(t) ₀ ^(t) ⁰ ^(+Δt) I _(t) dt  (49)

Suppose, for example, that irradiance was constant at 1,000 W/m² from12:00 pm to 12:30 μm. The corresponding irradiation would be 500 Wh/m².

Simulation models, however, typically require normalized irradiation,rather than irradiation, that is, Wh/m² per hour simplified as W/m².Normalized irradiation can also be referred to as average irradianceover some time interval. Irradiation is normalized by dividingirradiation by the time interval, that is, divide Equation (49) by Δt,which is equivalent to taking the expected value of the irradiance, suchthat:

Irradiation_(t) ₀ _(tot) ₀ _(+Δt) =E[∫ _(t) ₀ ^(t) ⁰ ^(+Δt) I _(t)dt]  (50)

where E[ ] is the expectation.

Equation (50) can be estimated directly by discretizing the equation,which converts the integral into a summation and uses a discrete set ofirradiance observations to solve the equation:

$\begin{matrix}{\overset{\_}{{Irradiation}_{{t_{0}{to}t_{0}} + {\Delta t}}} \approx {( \frac{1}{N} ){\sum\limits_{i = 0}^{N - 1}I_{t_{0} + {i*\frac{\Delta t}{N}}}}}} & (51)\end{matrix}$

For example, some locations collect one-minute irradiance data usingground-based irradiance sensors. Other locations may use satelliteimagery to produce irradiance estimates every half-hour and apply acloud motion vector approach to generate one-minute irradiance data. Forboth locations, irradiation normalized over a half-hour time intervalcan be produced by letting Δt equal 30 minutes and N equal 30 (there are30 one-minute observations in a 30-minute time interval). Thus, Equation(51) simplifies to:

$\begin{matrix}{\overset{\_}{{Irradiation}_{{t_{0}{to}t_{0}} + {30{\min.}}}}{\approx {( \frac{1}{30} ){\sum\limits_{i = 0}^{29}I_{t_{0} + i}}}}} & (52)\end{matrix}$

Suppose, for example, that irradiance was constant at 1,000 W/m² from12:00 pm to 12:30 pm. The corresponding normalized irradiation would be500 Wh/m² divided by 0.5 hours, or 1,000 W/m². In this case, irradianceand normalized irradiation are equal because irradiance was constantover the time interval over which the irradiation was normalized.

Apply Linear Interpolation to Irradiance

The direct approach to calculating normalized irradiation works betterwhen a sufficient number of irradiance observations exist to estimatenormalized irradiance with an acceptable level of accuracy. However,alternative approaches to estimating normalized irradiation must be usedwhen insufficient irradiance data is available. For instance, normalizedirradiation may be estimated by linearly interpolating between at leastthree consecutive irradiance observations and taking the sum of the areaunder the irradiance curve for a time interval within the irradianceobservations. FIG. 16 is a graph showing, by way of example, normalizedirradiation determined through linear interpolation of the irradianceplotted in FIG. 14A. The x-axis represents time of day and the y-axisrepresents irradiance. Clear sky irradiance and the clearness indexesare excluded from FIG. 16 and only irradiance observations are shown.

Normalized irradiation can be estimated using a fractional offset fbiased toward an earlier (or later) time t⁻¹ (or t₊₁) relative to thecenter time to, where the fractional offset f is between 0 and 1.Linearly interpolated irradiance is plotted as a pair of solid linesthat form an irradiance curve. The area of the irradiance curve underthe fractional offset f represents the irradiation over the timeinterval starting at t_(−f) and ending at t_(1−f). The fractional offsetf could also be set to the length of each regular interval of timeoccurring between each irradiance observation or other length of timeless than or equal to a regular time interval.

First, a slope is linearly interpolated between two consecutiveirradiance observations. A linear interpolation of I_(t) _(a) betweenI_(t) _(i) and I_(t) _(j) , where a is the fractional distance away fromt_(j), equals:

I _(t) _(a) =aI _(t) _(i) +(1−a)I _(t) _(j)   (53)

When i equals−1, j equals 0, and a equals f, then:

I _(t) _(f) =fI _(t) ⁻¹ +(1−f)I _(t) ₀   (54)

When i equals 1, j equals 0, and a equals 1−f, then:

I _(t) _(1−f) =(1−f)I _(t) ₁ +fI _(t) ₀   (55)

Next, the area under the irradiance curve for one time interval iscalculated. The area is calculated in two parts. First, the average ofthe irradiance at time −f and the irradiance at the current time aredetermined. Second, the average of the irradiance at the current timeand the irradiance at time 1−f are determined. Each part of the solutionis weighted according to the fractional part represented:

$\begin{matrix}{\overset{\_}{I_{t_{- f}{to}t_{1 - f}}} = {{f\lbrack \frac{I_{t_{f}} + I_{t_{0}}}{2} \rbrack} + {( {1 - f} )\lbrack \frac{I_{t_{0}} + I_{t_{1 - f}}}{2} \rbrack}}} & (56)\end{matrix}$

Substitute Equations (54) and (55) into Equation (56):

$\begin{matrix}{\overset{\_}{I_{t_{- f}{to}t_{1 - f}}} = {\frac{1}{2}\{ {{f\lbrack {{fI}_{t_{- 1}} + {( {1 - f} )I_{t_{0}}} + I_{t_{0}}} \rbrack} + {( {1 - f} )\lbrack {I_{t_{0}} + {( {1 - f} )I_{t_{1}}} + {fI}_{t_{0}}} \rbrack}} \}}} & (57)\end{matrix}$

Combine like terms and simplify. The result equals the product of theweighting factor array and the observed irradiance array:

$\begin{matrix}{\overset{\_}{I_{t_{- f}{to}t_{1 - f}}} = {\begin{bmatrix}\omega_{t_{- 1}} & \omega_{t_{0}} & \omega_{t_{1}}\end{bmatrix}\begin{bmatrix}I_{t_{- 1}} \\I_{t_{0}} \\I_{t_{1}}\end{bmatrix}}} & (58)\end{matrix}$

where the weighting factors

$\begin{bmatrix}\omega_{t_{- 1}} & \omega_{t_{0}} & \omega_{t_{1}}\end{bmatrix} = {{\lbrack {{\frac{f^{2}}{2}\ \frac{1}{2}} + f - {f^{2}\ \frac{( {1 - f} )^{2}}{2}}} \rbrack{for}0} \leq f \leq {1.}}$

The sum of the weighting factors equals 1.

Consider three cases of estimating normalized irradiation using Equation(58). FIG. 17 is a graph showing, by way of example, three cases ofdetermining normalized irradiation through linear interpolation of theirradiance plotted in FIG. 14A. The x-axis represents time of day andthe y-axis represents irradiance. In Case 1 (leftmost), normalizedirradiation starts and ends on irradiance observations t⁻¹ and t₀. InCase 2 (center), normalized irradiation is centered on an irradianceobservation t₀ with the start time t_(−1/2) corresponding to themidpoint between two observations t⁻¹ and to, and the end time t_(1/2)corresponding to the midpoint between two observations t₀ and t₁. InCase 3, normalized irradiation starts and ends one-quarter of a timeinterval t_(−1/4) and t_(3/4) before an irradiance observation t₀.

For each of the three cases, normalized irradiation is calculated bysetting the fraction (f) equal to 1, ½, and ¼, and calculating theweighting factors defined in Equation (58). FIG. 18 is a tablepresenting, by way of example, the normalized irradiation calculated forthe three cases of FIG. 17 . For example, the weighting factorspresented in the table of FIG. 17 combined with Equation (58) imply thatnormalized irradiation I_(t) ⁻¹ _(tot) ₀ for Case 1 equals:

$\begin{matrix}{\overset{\_}{I_{t_{- 1}{to}t_{0}}} = {{\frac{1}{2}I_{t_{- 1}}} + {\frac{1}{2}I_{t_{0}}}}} & (59)\end{matrix}$

Normalized irradiation for Case 2 and Case 3 are similarly calculated.

Apply Linear Interpolation to Clearness Indexes

Clear sky irradiance is not strictly linear. Empirical results presentedinfra help demonstrate that estimating normalized irradiation throughlinear interpolation of solar irradiance noticeably reduces estimationerror. The estimation error can be further reduced by adjusting thelinear interpolation to reflect that clear sky irradiance between anytwo observations is not strictly linear.

Irradiance can be expressed as the product of the clear sky irradianceI_(t) ^(ClearSky) and the clearness index Kt_(t)*. Substituting thesetwo expressions into Equation (50) and defining the interval to fromt_(−f) to t_(1−f) results in normalized irradiation of:

I _(t) _(−f) _(tot) _(1−f) =E[∫ _(t) _(−f) ^(t) ^(1−f) I _(t)^(ClearSky) Kt _(t) *dt]  (60)

The expectation of the product of two random variables equals theproduct of the expectation of each random variable separately, plus thecovariance between the two random variables. For example, if the randomvariables are X and Y, then E[XY]=E[X] E[Y]+COV[X,Y]. Thus, Equation(60) can be rewritten as:

I _(t) _(−f) _(tot) _(1−f) =E[∫ _(t) _(−f) ^(t) ^(1−f) I _(t)^(ClearSky) dt]E[∫ _(t) _(−f) ^(t) ^(1−f) I _(t) ^(ClearSky) Kt _(t)*dt]

+COV[I _(t) ^(ClearSky) ,Kt _(t)*]  (61)

The covariance between the clear sky irradiance I_(t) ^(ClearSky) andthe clearness index Kt_(t)* is approximately equal to 0, whether theclear sky irradiance changes very slowly relative to the clearnessindex, that is, under variable weather conditions, or the clearnessindex does not change, that is, overcast or clear sky conditions. As acalculated value, the clear sky irradiance I_(t) ^(ClearSky) is knownprecisely for all values of t. Thus, the clear sky irradiance I_(t)^(ClearSky) can be discretized, such that there are a sufficient numberof observations to result in an acceptable level of accuracy:

$\begin{matrix}{\overset{\_}{I_{t_{- f}{to}t_{1 - f}}} \approx {\lbrack {( \frac{1}{N} ){\sum\limits_{i = 0}^{N - 1}I_{t_{- f} + {i*\frac{\Delta t}{N}}}^{{Clear}{Sky}}}} \rbrack{E\lbrack {\int_{t_{- f}}^{t_{1 - f}}{Kt_{t}^{*}dt}} \rbrack}}} & (62)\end{matrix}$

Equation (62), however, still requires that the clearness index Kt_(t)*be evaluated. The linear interpolation methodology, as described supra,could be applied only to the clearness index portion of the calculation,rather than by applying linear interpolation to the all of theirradiance. FIGS. 19A-19B are graphs respectively showing, by way ofexample, determining clearness indexes through linear interpolation ofthe irradiance plotted of FIGS. 12A-12B. In both graphs, the x-axesrepresent time of day and the y-axes respectively represent irradianceand clearness index. The clear sky irradiance I_(t) ^(ClearSky) iscalculated exactly. The clearness index Kt_(t)* is estimated usinglinear interpolation.

Formally, the same linear interpolation methodology as was applied tosolar irradiance per Equation (58), described supra, can be used tocalculate the linear interpolation of the average clearness index as afunction of the fraction f Substitute the result of the linearinterpolation into Equation (62):

$\begin{matrix}{\overset{\_}{I_{t_{- f}{to}t_{1 - f}}} \approx {\lbrack {( \frac{1}{N} ){\sum\limits_{i = 0}^{N - 1}I_{t_{- f} + {i*\frac{\Delta t}{N}}}^{{Clear}{Sky}}}} \rbrack\{ {\begin{bmatrix}\omega_{t_{- 1}} & \omega_{t_{0}} & \omega_{t_{1}}\end{bmatrix}\begin{bmatrix}{Kt_{t_{- 1}}^{*}} \\{Kt_{t_{0}}^{*}} \\{Kt_{t_{1}}^{*}}\end{bmatrix}} \}}} & (63)\end{matrix}$

with the weighting factors equaling

$\begin{bmatrix}\omega_{t_{- 1}} & \omega_{t_{0}} & \omega_{t_{1}}\end{bmatrix} = {{\lbrack {{\frac{f^{2}}{2}\ \frac{1}{2}} + f - {f^{2}\ \frac{( {1 - f} )^{2}}{2}}} \rbrack{for}0} \leq f \leq {1.}}$

Empirically Derive Irradiance Weights

The weighting factor array for the irradiance (or clearness index) couldalso be empirically derived, that is, the values in [ω_(t) ⁻¹ ω_(t) ₀ω_(t) ₁ ] could be determined using an optimization approach. Here,weights are selected to minimize error, which can be accomplished bycomparing measured irradiation data, as typically measured usingground-based instrumentation, to solar irradiance data.

High-Speed Time Series Photovoltaic Fleet Energy Estimation

Using normalized irradiation, photovoltaic fleet energy production canbe estimated in a manner similar to fleet power production. A timeinterval is selected that is smaller than the time that has elapsedbetween consecutive irradiance observations. Normalized irradiation isthen estimated using one of the foregoing methodologies at a pointrelative to the time interval, which could be a fractional offset froman irradiance observation centered within a triplet of irradianceobservations. Similar to fleet power production estimation, clearnessindexes are evaluated as a ratio of the normalized irradiation and theclear sky irradiance, which provides normalized irradiation statisticsfor the photovoltaic fleet and energy statistics as a function of thenormalized irradiation statistics and an overall photovoltaic fleetpower rating.

DISCUSSION

The previous section derived five methodologies for estimatingnormalized irradiation. This section applies those methods to theSolarAnywhere Standard Resolution and SolarAnywhere Enhanced Resolutiondatabases of the SolarAnywhere service, cited supra. By way ofbackground, the SolarAnywhere service provides an Internet-accessiblesolar resource database that contains historical irradiance data from1998 through the present hour; real-time irradiance data; and forecastirradiance data for up to seven days beyond the current hour. TheSolarAnywhere Standard Resolution database provides data at a 10-kmspatial resolution and one-hour temporal resolution. The SolarAnywhereEnhanced Resolution database provides data at a 1-km spatial resolutionand half-hour temporal resolution. Satellite imagery is collected fromthe GOES West and GOES East satellites. The GOES West satellite collectsimages on the hour and 30 minutes after the hour. The GOES Eastsatellite collects images at 15 and 45 minutes past the hour.

By default, when a user wants the normalized irradiation centered arounda selected observation time, normalized irradiation is determinedthrough linear interpolation of solar irradiance with normalizedirradiation centered on an irradiance observation t₀ with the start timet_(−1/2) corresponding to the midpoint between two observations t⁻¹ andt₀, and the end time t_(1/2) corresponding to the midpoint between twoobservations t₀ and t₁. The default calculation corresponds to Case 2,as discussed supra with reference to FIG. 17 . Normalized irradiation iscalculated using either Equation (58) or (63) with f equal to ½.

The weighting factors are different, however, if the normalizedirradiation needs to start at the top of the hour (or, for EnhancedResolution data, at the top of the half-hour) with end of periodintegration. FIG. 20 is a table presenting, by way of example, theweighting factors for calculating normalized irradiation for start attop of hour (or half-hour for Enhanced Resolution data) with end ofperiod integration for the three cases of FIG. 17 .

Sample results help illustrate the increase in accuracy in estimatingnormalized irradiation achieved by respectively applying linearinterpolation to solar irradiance and empirically deriving irradianceweights per the third and fifth methodologies, discussed supra. Ananalysis was performed for ten locations and resolution scenarios toevaluate the improvement in the relative Mean Absolute Error (rMAE) forfour scenarios. Each scenario compared SolarAnywhere data to measuredhourly data (for SolarAnywhere Standard Resolution) or measuredhalf-hourly data (for SolarAnywhere Enhanced Resolution). A full year ofdata (2012) was used for all sites, except Hawaii, where a half year ofdata was used for the first half of 2012. The sample cases included: (1)Un-tuned irradiance; (2) Tuned irradiance; (3) Linear interpolation ofirradiance to produce normalized irradiation (third methodology); and(4) Optimized weights (fifth methodology). FIG. 21 is a tablepresenting, by way of example, the rMAE for irradiance and normalizedirradiation for the normalized irradiation estimates for the tenlocations and resolution scenarios. FIG. 22 is a graph showing, by wayof example, the relative reduction in rMAE for the normalizedirradiation estimates for the ten locations and resolution scenarios andcompares the linear interpolation that produced normalized irradiationto tuned irradiance, and the optimized weights to tuned irradiance. Thegraph in FIG. 22 suggests that the application of the foregoingmethodologies for estimating normalized irradiation resulted in a 3% to12% percent reduction in rMAE, a substantial reduction. Last, FIG. 23 isa set of graphs showing, by way of example, Standard Resolution data(half-hour, 1-km) in Hanford, CA, 2012 for the tuned versus un-tunedirradiance and normalized irradiation. FIG. 24 is a set of graphsshowing, by way of example, Enhanced Resolution data (half-hour, 1-km)in Hanford, CA, 2012 for the tuned versus un-tuned irradiance andnormalized irradiation. FIG. 25 is a set of graphs showing, by way ofexample, Enhanced Resolution data (half-hour, 1-km) in Campbell, Hawaii,first half of 2012 for the tuned versus un-tuned irradiance andnormalized irradiation. FIG. 26 is a set of graphs showing, by way ofexample, Standard Resolution data (half-hour, 1-km) in Penn State, PA,2012 for the tuned versus un-tuned irradiance and normalizedirradiation. FIG. 27 is a set of graphs showing, by way of example,Standard Resolution data (half-hour, 1-km) in Boulder, CO, 2012 for thetuned versus un-tuned irradiance and normalized irradiation. A carefulexamination of the figures illustrates a reduction in the spread of thedata for the tuned normalized irradiation.

Derivation of Empirical Models

The previous section developed the mathematical relationships used tocalculate irradiance and power statistics for the region associated witha photovoltaic fleet. The relationships between Equations (8), (28),(31), and (38) depend upon the ability to obtain point-to-pointcorrelation coefficients. This section presents empirically-derivedmodels that can be used to determine the value of the coefficients forthis purpose.

A mobile network of 25 weather monitoring devices was deployed in a 400meter by 400 meter grid in Cordelia Junction, CA, between Nov. 6, 2010,and Nov. 15, 2010, and in a 4,000 meter by 4,000 meter grid in Napa, CA,between Nov. 19, 2010, and Nov. 24, 2010. FIGS. 28A-28B are photographsshowing, by way of example, the locations of the Cordelia Junction andNapa high density weather monitoring stations.

An analysis was performed by examining results from Napa and CordeliaJunction using 10, 30, 60, 120 and 180 second time intervals over eachhalf-hour time period in the data set. The variance of the clearnessindex and the variance of the change in clearness index were calculatedfor each of the 25 locations for each of the two networks. In addition,the clearness index correlation coefficient and the change in clearnessindex correlation coefficient for each of the 625 possible pairs, 300 ofwhich are unique, for each of the two locations were calculated.

An empirical model is proposed as part of the methodology describedherein to estimate the correlation coefficient of the clearness indexand change in clearness index between any two points by using as inputsthe following: distance between the two points, cloud speed, and timeinterval. For the analysis, distances were measured, cloud speed wasimplied, and a time interval was selected.

The empirical models infra describe correlation coefficients between twopoints (i and j), making use of “temporal distance,” defined as thephysical distance (meters) between points i and j, divided by theregional cloud speed (meters per second) and having units of seconds.The temporal distance answers the question, “How much time is needed tospan two locations?”

Cloud speed was estimated to be six meters per second. Results indicatethat the clearness index correlation coefficient between the twolocations closely matches the estimated value as calculated using thefollowing empirical model:

ρ^(Kt) ^(i) ^(,Kt) ^(j) =exp(C₁×TemporalDistance)^(ClearnessPower)  (64)

where TemporalDistance=Distance (meters)/CloudSpeed (meters per second),ClearnessPower=In(C₂Δt)−9.3, such that 5≤k≤15, where the expected valueis k=9.3, Δt is the desired output time interval (seconds), C₁=10⁻³seconds⁻¹, and C₂=1 seconds⁻¹.

Results also indicate that the correlation coefficient for the change inclearness index between two locations closely matches the valuescalculated using the following empirical relationship:

ρ^(ΔKt) ^(i) ^(,ΔKt) ^(j) =(ρ^(Kt) ^(i) ^(,Kt) ^(j))^(ΔClearnessPower)  (65)

where ρ^(Kt) ^(i) ^(,Kt) ^(j) is calculated using Equation (64) and

${{\Delta{ClearnessPower}} = {1 + \frac{140}{C_{2}\Delta t}}},$

such that 100≤m≤200, where the expected value is m=140.

Empirical results also lead to the following models that may be used totranslate the variance of clearness index and the variance of change inclearness index from the measured time interval (Δt ref) to the desiredoutput time interval (Δt).

$\begin{matrix}{\sigma_{{Kt}_{\Delta t}}^{2} = {\sigma_{{Kt}_{\Delta t{ref}}}^{2}{\exp\lbrack {1 - ( \frac{\Delta t}{\Delta t{ref}} )^{C_{3}}} \rbrack}}} & (66)\end{matrix}$ $\begin{matrix}{{\sigma_{\Delta{Kt}_{\Delta t}}^{2} = {\sigma_{\Delta{Kt}_{\Delta t{ref}}}^{2}\{ {1 - {2\lbrack {1 - ( \frac{\Delta t}{\Delta t{ref}} )^{C_{3}}} \rbrack}} \}}}{{{{where}C_{3}} = {0.1 \leq C_{3} \leq 0.2}},}} & (67)\end{matrix}$

where the expected value is C₃=0.15.

FIGS. 29A-29B are graphs depicting, by way of example, the adjustmentfactors plotted for time intervals from 10 seconds to 300 seconds. Forexample, if the variance is calculated at a 300-second time interval andthe user desires results at a 10-second time interval, the adjustmentfor the variance clearness index would be 1.49.

These empirical models represent a valuable means to rapidly calculatecorrelation coefficients and translate time interval withreadily-available information, which avoids the use ofcomputation-intensive calculations and high-speed streams of data frommany point sources, as would otherwise be required.

Validation

Equations (64) and (65) were validated by calculating the correlationcoefficients for every pair of locations in the Cordelia Junctionnetwork and the Napa network at half-hour time periods. The correlationcoefficients for each time period were then weighted by thecorresponding variance of that location and time period to determineweighted average correlation coefficient for each location pair. Theweighting was performed as follows:

${{\overset{\_}{\rho^{{Kt}^{i},{Kt}^{j}}} = \frac{{\sum}_{t = 1}^{T}\sigma_{{{Kt} - i},j_{t}}^{2}\rho_{t}^{{Kt}^{i},{Kt}^{j}}}{{\sum}_{t = 1}^{T}\sigma_{{{Kt} - i},j_{t}}^{2}}},{and}}{\overset{\_}{\rho^{{\Delta{Kt}^{i}},{\Delta{Kt}^{j}}}} = {\frac{{{\sum}_{t = 1}^{T}\sigma_{{\Delta{Kt}} - i}^{2}},{j_{t}\rho_{t}^{{\Delta{Kt}^{i}},{\Delta{Kt}^{j}}}}}{{\sum}_{i = 1}^{T}\sigma_{{{\Delta{Kt}} - i},j_{t}}^{2}}.}}$

FIGS. 30A-30F are graphs depicting, by way of example, the measured andpredicted weighted average correlation coefficients for each pair oflocations versus distance. FIGS. 31A-31F are graphs depicting, by way ofexample, the same information as depicted in FIGS. 30A-30F versustemporal distance, based on the assumption that cloud speed was sixmeters per second. Several observations can be drawn based on theinformation provided by the FIGS. 30A-30F and 31A-31F. First, for agiven time interval, the correlation coefficients for both the clearnessindex and the change in the clearness index follow an exponentialdecline pattern versus distance (and temporal distance). Second, thepredicted results are a good representation of the measured results forboth the correlation coefficients and the variances, even though theresults are for two separate networks that vary in size by a factor of100. Third, the change in the clearness index correlation coefficientconverges to the clearness correlation coefficient as the time intervalincreases. This convergence is predicted based on the form of theempirical model because ΔClearnessPower approaches one as Δt becomeslarge.

Equations (66) and (67) were validated by calculating the averagevariance of the clearness index and the variance of the change in theclearness index across the 25 locations in each network for everyhalf-hour time period. FIGS. 32A-32F are graphs depicting, by way ofexample, the predicted versus the measured variances of clearnessindexes using different reference time intervals. FIGS. 33A-33F aregraphs depicting, by way of example, the predicted versus the measuredvariances of change in clearness indexes using different reference timeintervals. FIGS. 32A-32F and 33A-33F suggest that the predicted resultsare similar to the measured results.

DISCUSSION

The point-to-point correlation coefficients calculated using theempirical forms described supra refer to the locations of specificphotovoltaic power production sites. Importantly, note that the dataused to calculate these coefficients was not obtained from time sequencemeasurements taken at the points themselves. Rather, the coefficientswere calculated from fleet-level data (cloud speed), fixed fleet data(distances between points), and user-specified data (time interval).

The empirical relationships of the foregoing types of empiricalrelationships may be used to rapidly compute the coefficients that arethen used in the fundamental mathematical relationships. The methodologydoes not require that these specific empirical models be used andimproved models will become available in the future with additional dataand analysis.

Example

This section provides a complete illustration of how to apply themethodology using data from the Napa network of 25 irradiance sensors onNov. 21, 2010. In this example, the sensors served as proxies for anactual 1 kW photovoltaic fleet spread evenly over the geographicalregion as defined by the sensors. For comparison purposes, a directmeasurement approach is used to determine the power of this fleet andthe change in power, which is accomplished by adding up the 10-secondoutput from each of the sensors and normalizing the output to a 1 kWsystem. FIGS. 34A-34F are graphs and a diagram depicting, by way ofexample, application of the methodology described herein to the Napanetwork.

The predicted behavior of the hypothetical photovoltaic fleet wasseparately estimated using the steps of the methodology described supra.The irradiance data was measured using ground-based sensors, althoughother sources of data could be used, including from existingphotovoltaic systems or satellite imagery. As shown in FIG. 34A, thedata was collected on a day with highly variable clouds with one-minuteglobal horizontal irradiance data collected at one of the 25 locationsfor the Napa network and specific 10-second measured power outputrepresented by a blue line. This irradiance data was then converted fromglobal horizontal irradiance to a clearness index. The mean clearnessindex, variance of clearness index, and variance of the change inclearness index were then calculated for every 15-minute period in theday. These calculations were performed for each of the 25 locations inthe network. Satellite-based data or a statistically-significant subsetof the ground measurement locations could have also served in place ofthe ground-based irradiance data. However, if the data had beencollected from satellite regions, an additional translation from areastatistics to average point statistics would have been required. Theaveraged irradiance statistics from Equations (1), (10), and (11) areshown in FIG. 34B, where standard deviation (a) is presented, instead ofvariance (σ²) to plot each of these values in the same units.

In this example, the irradiance statistics need to be translated sincethe data were recorded at a time interval of 60 seconds, but the desiredresults are at a 10-second resolution. The translation was performedusing Equations (66) and (67) and the result is presented in FIG. 34C.

The details of the photovoltaic fleet configuration were then obtained.The layout of the fleet is presented in FIG. 34D. The details includethe location of the each photovoltaic system (latitude and longitude),photovoltaic system rating (1/25 kW), and system orientation (all arehorizontal).

Equation (48), and its associated component equations, were used togenerate the time series data for the photovoltaic fleet with theadditional specification of the specific empirical models, as describedin Equations (64) through (67). The resulting fleet power and change inpower is presented represented by the red lines in FIGS. 34E and 34F.

Probability Density Function

The conversion from area statistics to point statistics relied upon twoterms A_(Kt) and A_(ΔKt) to calculate σ_(Kt) ² and σ_(ΔKt) ²,respectively. This section considers these terms in more detail. Forsimplicity, the methodology supra applies to both Kt and ΔKt, so thisnotation is dropped. Understand that the correlation coefficient ρ^(ij)could refer to either the correlation coefficient for clearness index orthe correlation coefficient for the change in clearness index, dependingupon context. Thus, the problem at hand is to evaluate the followingrelationship:

$\begin{matrix}{A = {( \frac{1}{N^{2}} ){\sum\limits_{i = 1}^{N}{\sum\limits_{j = 1}^{N}\rho^{i,j}}}}} & (68)\end{matrix}$

The computational effort required to calculate the correlationcoefficient matrix can be substantial. For example, suppose that the onewants to evaluate variance of the sum of points within a one-squarekilometer satellite region by breaking the region into one millionsquare meters (1,000 meters by 1,000 meters). The complete calculationof this matrix requires the examination of one trillion (10¹²) locationpair combinations. A heuristical approach to simplifying the solutionspace from exponential to linear is discussed supra with reference toFIGS. 7-10 .

Discrete Formulation

The calculation can be simplified using the observation that many of theterms in the correlation coefficient matrix are identical. For example,the covariance between any of the one million points and themselvesis 1. This observation can be used to show that, in the case of arectangular region that has dimension of H by W points (total of N) andthe capacity is equal distributed across all parts of the region that:

$\begin{matrix}{{( \frac{1}{N^{2}} ){\sum\limits_{i = 1}^{N}{\sum\limits_{j = 1}^{N}\rho^{i,j}}}} = {( \frac{1}{N^{2}} )\lbrack {{\sum\limits_{i = 0}^{H - 1}{\sum\limits_{j = 0}^{i}{{2^{k}\lbrack {( {H - i} )( {W - j} )} \rbrack}\rho^{d}}}} + {\sum\limits_{i = 0}^{W - 1}{\sum\limits_{j = 0}^{i}{{2^{k}\lbrack {( {W - i} )( {H - j} )} \rbrack}\rho^{d}}}}} \rbrack}} & (69)\end{matrix}$ ${{where}:}{k = \begin{matrix}{{- 1},} & {{{when}i} = {{0{and}j} = 0}} \\{1,} & {{{when}j} = {{0{or}j} = i}} \\{2,} & {{{when}0} < j < i}\end{matrix}}$

When the region is a square, a further simplification can be made.

$\begin{matrix}{{{( \frac{1}{N^{2}} ){\sum\limits_{i = 1}^{N}{\sum\limits_{j = 1}^{N}\rho^{i,j}}}} = {( \frac{1}{N^{2}} )\lbrack {\sum\limits_{i = 0}^{\sqrt{N} - 1}{\sum\limits_{j = 0}^{i}{2^{k}( {\sqrt{N} - i} )( {\sqrt{N} - j} )\rho^{d}}}} \rbrack}}{{where}:}{{k = \begin{matrix}{0,} & {{{when}i} = {{0{and}j} = 0}} \\{2,} & {{{when}j} = {{0{or}j} = i}} \\{3,} & {{{when}0} < j < i}\end{matrix}},{and}}{d = {( \sqrt{i^{2} + j^{2}} ){( {\frac{\sqrt{Area}}{N} - 1} ).}}}} & (70)\end{matrix}$

The benefit of Equation (70) is that there are

$\frac{N - \sqrt{N}}{2}$

rather than N² unique combinations that need to be evaluated. In theexample above, rather than requiring one trillion possible combinations,the calculation is reduced to one-half million possible combinations.

Continuous Formulation

Even given this simplification, however, the problem is stillcomputationally daunting, especially if the computation needs to beperformed repeatedly in the time series. Therefore, the problem can berestated as a continuous formulation in which case a proposedcorrelation function may be used to simplify the calculation. The onlyvariable that changes in the correlation coefficient between any of thelocation pairs is the distance between the two locations; all othervariables are the same for a given calculation. As a result, Equation(70) can be interpreted as the combination of two factors: theprobability density function for a given distance occurring and thecorrelation coefficient at the specific distance.

Consider the probability density function. The actual probability of agiven distance between two pairs occurring was calculated for a 1,000meter×1,000 meter grid in one square meter increments. The evaluation ofone trillion location pair combination possibilities was evaluated usingEquation (68) and by eliminating the correlation coefficient from theequation. FIG. 35 is a graph depicting, by way of example, an actualprobability distribution for a given distance between two pairs oflocations, as calculated for a 1,000 meter×1,000 meter grid in onesquare meter increments.

The probability distribution suggests that a continuous approach can betaken, where the goal is to find the probability density function basedon the distance, such that the integral of the probability densityfunction times the correlation coefficient function equals:

A=∫f(D)ρ(d)dD  (71)

An analysis of the shape of the curve shown in FIG. 35 suggests that thedistribution can be approximated through the use of two probabilitydensity functions. The first probability density function is a quadraticfunction that is valid between 0 and √{square root over (Area)}.

$\begin{matrix}{f_{Quad} = \{ \begin{matrix}{( \frac{6}{Area} )( {D - \frac{D^{2}}{\sqrt{Area}}} )} & {{{for}0} \leq D \leq \sqrt{Area}} \\0 & {{{for}D} > \sqrt{Area}}\end{matrix} } & (72)\end{matrix}$

This function is a probability density function because integratingbetween 0 and √{square root over (Area)} equals 1, that is,P[0≤D≤√{square root over (Area)}]=f₀ ^(√{square root over (Area)})f_(Quad.)dD=1.

The second function is a normal distribution with a mean of √{squareroot over (Area)} and standard deviation of 0.1 √{square root over(Area)}.

$\begin{matrix}{f_{Norm} = {( \frac{1}{0.1*\sqrt{Area}} )( \frac{1}{\sqrt{2\pi}} )e^{{- {(\frac{1}{2})}}{(\frac{D - \sqrt{Area}}{0.1*\sqrt{Area}})}^{2}}}} & (73)\end{matrix}$

Likewise, integrating across all values equals 1.

To construct the desired probability density function, take, forinstance, 94 percent of the quadratic density function plus six percentof the normal density function.

f=0.94∫₀ ^(√{square root over (Area)}) f _(Quad) dD+0.06∫_(−∞) ^(+∞) f_(Norm) dD  (74)

FIG. 36 is a graph depicting, by way of example, a matching of theresulting model to an actual distribution.

The result is that the correlation matrix of a square area with uniformpoint distribution as N gets large can be expressed as follows, firstdropping the subscript on the variance since this equation will work forboth Kt and ΔKt.

A≈[0.94∫₀ ^(√{square root over (Area)}) f _(Quad)ρ(D)dD+0.06∫_(−∞) ^(+∞)f _(Norm)ρ(D)dD]  (75)

where ρ(D) is a function that expresses the correlation coefficient as afunction of distance (D).

Area to Point Conversion Using Exponential Correlation Coefficient

Equation (75) simplifies the problem of calculating the correlationcoefficient and can be implemented numerically once the correlationcoefficient function is known. This section demonstrates how a closedform solution can be provided, if the functional form of the correlationcoefficient function is exponential.

Noting the empirical results as shown in the graph in FIGS. 30A-30F, anexponentially decaying function can be taken as a suitable form for thecorrelation coefficient function. Assume that the functional form ofcorrelation coefficient function equals:

$\begin{matrix}{{\rho(D)} = e^{\frac{xD}{\sqrt{Area}}}} & (76)\end{matrix}$

Let Quad be the solution to ∫₀^(√{square root over (Area)})f_(Quad.)ρ(D) dD.

$\begin{matrix}{{Quad} = {{{\int}_{0}^{\sqrt{Area}}f_{Quad}{\rho(D)}{dD}} = {( \frac{6}{Area} ){\int}_{0}^{\sqrt{Area}}{( {D - \frac{D^{2}}{\sqrt{Area}}} )\lbrack e^{\frac{xD}{\sqrt{Area}}} \rbrack}{dD}}}} & (77)\end{matrix}$

Integrate to solve.

$\begin{matrix}{{Quad} = {(6)\lbrack {{( {{\frac{x}{\sqrt{Area}}D} - 1} )e^{\frac{xD}{\sqrt{Area}}}} - {( {{( \frac{x}{\sqrt{Area}} )^{2}D^{2}} - {2\frac{x}{\sqrt{Area}}D} + 2} )e^{\frac{xD}{\sqrt{Area}}}}} \rbrack}} & (78)\end{matrix}$

Complete the result by evaluating at D equal to √{square root over(Area)} for the upper bound and 0 for the lower bound. The result is:

$\begin{matrix}{{Quad} = {( \frac{6}{x^{3}} )\lbrack {{( {x - 2} )( {e^{x} + 1} )} + 4} \rbrack}} & (79)\end{matrix}$

Next, consider the solution to ∫_(−∞) ^(+∞)f_(Norm.)ρ(D)dD, which willbe called Norm.

$\begin{matrix}{{Norm} = {( \frac{1}{\sigma} )( \frac{1}{\sqrt{2\pi}} ){\int}_{- \infty}^{+ \infty}e^{{- {(\frac{1}{2})}}{(\frac{D - \mu}{\sigma})}^{2}}e^{\frac{xD}{\sqrt{Area}}}{dD}}} & (80)\end{matrix}$

where μ=√{square root over (Area)} and σ=0.1 √{square root over (Area)}.Simplifying:

$\begin{matrix}{{Norm} = {\lbrack e^{\frac{x}{\sqrt{Area}}{({\mu + {\frac{1}{2}\frac{x}{\sqrt{Area}}\sigma^{2}}})}} \rbrack( \frac{1}{\sigma} )( \frac{1}{\sqrt{2\pi}} ){\int}_{- \infty}^{+ \infty}e^{- {{(\frac{1}{2})}\lbrack\frac{D - {({\mu + {\frac{x}{\sqrt{Area}}\sigma^{2}}})}}{\sigma}\rbrack}^{2}}{dD}}} & (81)\end{matrix}$ $\begin{matrix}{{{Substitute}z} = {{\frac{D - ( {\mu + {\frac{x}{\sqrt{Area}}\sigma^{2}}} )}{\sigma}{and}\sigma{dz}} = {{{dD}.{Norm}} = {\lbrack e^{\frac{x}{\sqrt{Area}}{({\mu + {\frac{1}{2}\frac{x}{\sqrt{Area}}\sigma^{2}}})}} \rbrack( \frac{1}{\sqrt{2\pi}} ){\int}_{- \infty}^{+ \infty}e^{{- {(\frac{1}{2})}}z^{2}}{dz}}}}} & (82)\end{matrix}$

Integrate and solve.

$\begin{matrix}{{Norm} = {e^{\frac{x}{\sqrt{Area}}}( {\mu + {\frac{1}{2}\frac{x}{\sqrt{Area}}\sigma^{2}}} )}} & (83)\end{matrix}$

Substitute the mean of √{square root over (Area)} and the standarddeviation of 0.1 √{square root over (Area)} into Equation (75).

Norm=e ^(x(1+0.005x))  (84)

Substitute the solutions for Quad and Norm back into Equation (75). Theresult is the ratio of the area variance to the average point variance.This ratio was referred to as A (with the appropriate subscripts andsuperscripts) supra.

$\begin{matrix}{A = {{{0.9}4{( \frac{6}{x^{3}} )\lbrack {{( {x - 2} )( {e^{x} + 1} )} + 4} \rbrack}} + {{0.0}6e^{x({1 + {{0.0}05x}})}}}} & (85)\end{matrix}$

Example

This section illustrates how to calculate A for the clearness index fora satellite pixel that covers a geographical surface area of 1 km by 1km (total area of 1,000,000 m²), using a 60-second time interval, and 6meter per second cloud speed. Equation (76) required that thecorrelation coefficient be of the form

$e^{\frac{xD}{\sqrt{Area}}}.$

The empirically derived result in Equation (64) can be rearranged andthe appropriate substitutions made to show that the correlationcoefficient of the clearness index equals

${\exp\lbrack \frac{( {{\ln\Delta t} - {9.3}} )D}{1000{Cloudspeed}} \rbrack}.$

Multiply the exponent by

$\frac{\sqrt{Area}}{\sqrt{Area}},$

so that the correlation coefficient equals

$\exp{\{ {\lbrack \frac{( {{\ln\Delta t} - 9.3} )\sqrt{Area}}{1000{CloudSpeed}} \rbrack\lbrack \frac{D}{\sqrt{Area}} \rbrack} \}.}$

This expression is now in the correct form to apply Equation (85), where

$x = {\frac{( {{\ln\Delta t} - 9.3} )\sqrt{Area}}{1000{CloudSpeed}}.}$

Inserting the assumptions results in

${x = {\frac{( {{\ln 60} - {9.3}} )\sqrt{1,000,000}}{1000 \times 6} = {{- {0.8}}6761}}},$

which is applied to Equation (85). The result is that A equals 65percent, that is, the variance of the clearness index of the satellitedata collected over a 1 km² region corresponds to 65 percent of thevariance when measured at a specific point. A similar approach can beused to show that the A equals 27 percent for the change in clearnessindex. FIG. 37 is a graph depicting, by way of example, resultsgenerated by application of Equation (85).

Time Lag Correlation Coefficient

This section presents an alternative approach to deriving the time lagcorrelation coefficient. The variance of the sum of the change in theclearness index equals:

σ_(ΣΔKt) ²=VAR[Σ(Kt ^(Δt) −Kt)]  (86)

where the summation is over N locations. This value and thecorresponding subscripts have been excluded for purposes of notationalsimplicity.

Divide the summation into two parts and add several constants to theequation:

$\begin{matrix}{\sigma_{\sum{\Delta{Kt}}}^{2} = {{VAR}\lbrack {{\sigma_{\sum{Kt}^{\Delta t}}( \frac{\sum{Kt}^{\Delta t}}{\sigma_{\sum{Kt}^{\Delta t}}} )} - {\sigma_{\sum{Kt}}( \frac{\sum{Kt}}{\sigma_{\sum{Kt}}} )}} \rbrack}} & (87)\end{matrix}$

Since σ_(ΣKt) _(ΔKt) ≈σ_(ΣKt)(or σ_(ΣKt) _(ΔKt) =σ_(ΣKt) if the firstterm in Kt and the last term in Kt^(Δt) are the same):

$\begin{matrix}{\sigma_{\sum{\Delta{Kt}}}^{2} = {\sigma_{\sum{Kt}}^{2}{{VAR}\lbrack {\frac{\sum{Kt}^{\Delta t}}{\sigma_{\sum{Kt}^{\Delta t}}} - \frac{\sum{Kt}}{\sigma_{\sum{Kt}}}} \rbrack}}} & (88)\end{matrix}$

The variance term can be expanded as follows:

$\begin{matrix}{\sigma_{\sum{\Delta{Kt}}}^{2} = {\sigma_{\sum{Kt}}^{2}\{ {\frac{{VAR}\lbrack {\sum{Kt}^{\Delta t}} \rbrack}{\sigma_{\sum{Kt}^{\Delta t}}^{2}} + \frac{V{{AR}\lbrack {\sum{Kt}} \rbrack}}{\sigma_{\sum{Kt}}^{2}} - \frac{2{{COV}\lbrack {{\sum{Kt}},{\sum{Kt}^{\Delta t}}} \rbrack}}{\sigma_{\sum{Kt}}\sigma_{\sum{Kt}^{\Delta t}}}} \}}} & (89)\end{matrix}$SinceCOV[∑Kt, ∑Kt^(Δt)] = σ_(∑Kt)σ_(∑KC^(Δt))ρ^(∑Kt, ∑Kt^(Δt)),

the first two terms equal one and the covariance term is replaced by thecorrelation coefficient.

σ_(ΣΔKt) ²=2σ_(ΣKt) ²(1−ρ^(ΣKt,ΣKt) ^(Δt) )  (90)

This expression rearranges to:

$\begin{matrix}{\rho^{{\sum{Kt}},{\sum{Kt}^{\Delta t}}} = {1 - {\frac{1}{2}\frac{\sigma_{\sum{\Delta{Kt}}}^{2}}{\sigma_{\sum{Kt}}^{2}}}}} & (91)\end{matrix}$

Assume that all photovoltaic plant ratings, orientations, and areaadjustments equal to one, calculate statistics for the clearness aloneusing the equations described supra and then substitute. The result is:

$\begin{matrix}{\rho^{{\sum{Kt}},{\sum{Kt}^{\Delta t}}} = {1 - \frac{P^{\Delta Kt}\sigma_{\overset{\_}{\Delta{Kt}}}^{2}}{2P^{Kt}\sigma_{\overset{\_}{Kt}}^{2}}}} & (92)\end{matrix}$

Relationship Between Time Lag Correlation Coefficient and Power/Changein Power Correlation Coefficient

This section derives the relationship between the time lag correlationcoefficient and the correlation between the series and the change in theseries for a single location.

$\rho^{P,{\Delta P}} = {\frac{{COV}\lbrack {P,{\Delta P}} \rbrack}{\sqrt{\sigma_{P}^{2}\sigma_{\Delta P}^{2}}} = {\frac{{COV}\lbrack {P,{P^{\Delta t} - P}} \rbrack}{\sqrt{\sigma_{P}^{2}\sigma_{\Delta P}^{2}}} = \frac{{{COV}\lbrack {P,P^{\Delta t}} \rbrack} - \sigma_{P}^{2}}{\sqrt{\sigma_{P}^{2}\sigma_{\Delta P}^{2}}}}}$Sinceσ_(ΔP)² = VAR[P^(Δt) − P] = σ_(P)² + σ_(P^(Δt))² − 2COV[P, P^(Δt)]and${{{COV}\lbrack {P,P^{\Delta t}} \rbrack} = {\rho^{P,P^{\Delta t}}\sqrt{\sigma_{P}^{2}\sigma_{P^{\Delta t}}^{2}}}},$${{then}\rho^{P,{\Delta P}}} = {\frac{{\rho^{P,P^{\Delta t}}\sqrt{\sigma_{P}^{2}\sigma_{P^{\Delta t}}^{2}}} - \sigma_{P}^{2}}{\sqrt{\sigma_{P}^{2}( {\sigma_{P}^{2} + \sigma_{P^{\Delta t}}^{2} - {2\rho^{P,P^{\Delta t}}\sqrt{\sigma_{P}^{2}\sigma_{P^{\Delta t}}^{2}}}} )}}.}$

Since σ_(P) ²≈σ_(pΔt) ², this expression can be further simplified.Then, square both expression and solve for the time lag correlationcoefficient:

ρ^(P,P) ^(Δt) =1−2(ρ^(P,ΔP))²

Correlation Coefficients Between Two Regions

Assume that the two regions are squares of the same size, each side withN points, that is, a matrix with dimensions of √{square root over (N)}by √{square root over (N)} points, where √{square root over (N)} is aninteger, but are separated by one or more regions. Thus:

$\begin{matrix}{{\sum\limits_{i = 1}^{N}{\sum\limits_{j = 1}^{N}{( \frac{1}{N^{2}} )\rho^{i,j}}}} = {( \frac{1}{N^{2}} )\lbrack {\sum\limits_{i = 0}^{\sqrt{N} - 1}{\sum\limits_{j = {1 - \sqrt{N}}}^{\sqrt{N} - 1}{{k( {\sqrt{N} - i} )}( {\sqrt{N} - {❘j❘}} )\rho^{d}}}} \rbrack}} & (93)\end{matrix}$ ${{where}k} = \{ {\begin{matrix}1 & {{{when}i} = 0} \\2 & {{{when}i} > 0}\end{matrix},{d = {( \sqrt{i^{2} + ( {j + {M\sqrt{N}}} )^{2}} )( \frac{\sqrt{Area}}{\sqrt{N} - 1} )}},} $

and M equals the number of regions.

FIG. 38 is a graph depicting, by way of example, the probability densityfunction when regions are spaced by zero to five regions. FIG. 38suggests that the probability density function can be estimated usingthe following distribution:

$\begin{matrix}{f = \{ \begin{matrix}{ {1 - ( \frac{{Spacing} - D}{\sqrt{Area}} } )\ } & {{{{for}{Spacing}} - \sqrt{Area}} \leq D \leq {Spacing}} \\ {1 + ( \frac{{Spacing} - D}{\sqrt{Area}} } ) & {{{for}{Spacing}} \leq D \leq {{Spacing} + \sqrt{Area}}} \\0 & {{all}{esle}}\end{matrix} } & (94)\end{matrix}$

This function is a probability density function because the integrationover all possible values equals zero. FIG. 39 is a graph depicting, byway of example, results by application of this model.

While the invention has been particularly shown and described asreferenced to the embodiments thereof, those skilled in the art willunderstand that the foregoing and other changes in form and detail maybe made therein without departing from the spirit and scope.

What is claimed is:
 1. A system for estimating photovoltaic energythrough empirical derivation with the aid of a digital computer,comprising: at least one computer processor configured to: obtain solarirradiance data comprising a set of irradiance observations that havebeen recorded for a location at which a photovoltaic plant can beoperated with each irradiance observation in the set being separated byregular intervals of time; obtain measured irradiance associated with atleast some of the irradiance observations; obtain a set of clear skyirradiance with each clear sky irradiance in the set corresponding toone of the irradiance observations; empirically derive using anoptimization approach a weighting factor array using at least some ofthe measured irradiance and the irradiance observations associated withthe at least some measured irradiance; estimate a set of normalizedirradiation, with each normalized irradiation in the set correspondingto one of the irradiance observations, using the weighing factor arrayand the irradiance observations; form a time series of clearness indexeswith each clearness index in the time series corresponding to one of theirradiance observations, each clearness index comprising a ratio of theirradiance observation's corresponding normalized irradiation estimateand the irradiance observation's corresponding clear sky irradiance; andforecast photovoltaic energy production for the photovoltaic plant as afunction of the time series of the clearness indexes and photovoltaicplant's power rating.
 2. A system according to claim 1, wherein theweighting factor array comprises a plurality of weighing factors andeach of the weighing factors is selected to minimize error between oneof the irradiance observations and the associated measured irradiance.3. A system according to claim 2, wherein the measured irradiance ismeasured using ground based instrumentation.
 4. A system according toclaim 1, wherein the normalized irradiation is obtained using anirradiance array formed by the irradiance observation occurring beforethe one irradiance observation, the one irradiance observation, and theirradiance observation occurring after the one irradiance observation.5. A system according to claim 4, wherein the normalized irradiationcomprises a product of the weighing factor array and the irradiancearray.
 6. A system according to claim 1, the at least one computerprocessor further configured to: determine an average of the irradianceobservations; and determine a set of sky clearness indexes as a ratio ofeach of the irradiance observations and clear sky global horizontalirradiance, wherein the normalized irradiation is further determinedusing the average of the irradiance observation and a sky clearnessindex array formed by the sky clearness index corresponding to theirradiance observation occurring before the one irradiance observation,the sky clearness index corresponding to the one irradiance observation,and the sky clearness index corresponding to the irradiance observationoccurring after the one irradiance observation.
 7. A system according toclaim 1, wherein a power grid connected to the photovoltaic plant isoperated using the forecasted photovoltaic energy production.
 8. Asystem according to claim 1, the at least one computer processor furtherconfigured to: obtain sets of irradiance observations that have beenrecorded for a plurality of locations at which a photovoltaic fleetcomprising a plurality of photovoltaic plants can be operated; estimatesets of normalized irradiation for each of the locations and formingtime series of clearness indexes in the computer with the sets ofnormalized irradiation; and forecast photovoltaic energy production forthe photovoltaic fleet as a function of the time series of the clearnessindexes and photovoltaic plants' power ratings.
 9. A method according toclaim 8, wherein the photovoltaic fleet is integrated into a power gridand wherein the power grid is operated based on the forecastphotovoltaic energy production for the photovoltaic fleet.
 10. A systemaccording to claim 1, wherein a sum of weighting factors in theweighting factor array equals
 1. 11. A method for estimatingphotovoltaic energy through empirical derivation with the aid of adigital computer, comprising steps of: obtaining solar irradiance datacomprising a set of irradiance observations that have been recorded fora location at which a photovoltaic plant can be operated with eachirradiance observation in the set being separated by regular intervalsof time; obtaining measured irradiance associated with at least some ofthe irradiance observations; obtaining a set of clear sky irradiancewith each clear sky irradiance in the set corresponding to one of theirradiance observations; empirically deriving using an optimizationapproach a weighting factor array using at least some of the measuredirradiance and the irradiance observations associated with the at leastsome measured irradiance; estimating a set of normalized irradiation,with each normalized irradiation in the set corresponding to one of theirradiance observations, using the weighing factor array and theirradiance observations; forming a time series of clearness indexes witheach clearness index in the time series corresponding to one of theirradiance observations, each clearness index comprising a ratio of theirradiance observation's corresponding normalized irradiation estimateand the irradiance observation's corresponding clear sky irradiance; andforecasting photovoltaic energy production for the photovoltaic plant asa function of the time series of the clearness indexes and photovoltaicplant's power rating, wherein the steps are performed by at least onesuitably-programmed computer.
 12. A method according to claim 11,wherein the weighting factor array comprises a plurality of weighingfactors and each of the weighing factors is selected to minimize errorbetween one of the irradiance observations and the associated measuredirradiance.
 13. A method according to claim 12, wherein the measuredirradiance is measured using ground based instrumentation.
 14. A methodaccording to claim 11, wherein the normalized irradiation is obtainedusing an irradiance array formed by the irradiance observation occurringbefore the one irradiance observation, the one irradiance observation,and the irradiance observation occurring after the one irradianceobservation.
 15. A method according to claim 14, wherein the normalizedirradiation comprises a product of the weighing factor array and theirradiance array.
 16. A method according to claim 11, furthercomprising: determining an average of the irradiance observations; anddetermining a set of sky clearness indexes as a ratio of each of theirradiance observations and clear sky global horizontal irradiance,wherein the normalized irradiation is further determined using theaverage of the irradiance observation and a sky clearness index arrayformed by the sky clearness index corresponding to the irradianceobservation occurring before the one irradiance observation, the skyclearness index corresponding to the one irradiance observation, and thesky clearness index corresponding to the irradiance observationoccurring after the one irradiance observation.
 17. A method accordingto claim 11, wherein a power grid connected to the photovoltaic plant isoperated using the forecasted photovoltaic energy production.
 18. Amethod according to claim 11, further comprising: obtaining sets ofirradiance observations that have been recorded for a plurality oflocations at which a photovoltaic fleet comprising a plurality ofphotovoltaic plants can be operated; estimating sets of normalizedirradiation for each of the locations and forming time series ofclearness indexes in the computer with the sets of normalizedirradiation; and forecasting photovoltaic energy production for thephotovoltaic fleet as a function of the time series of the clearnessindexes and photovoltaic plants' power ratings.
 19. A method accordingto claim 18, wherein the photovoltaic fleet is integrated into a powergrid and wherein the power grid is operated based on the forecastphotovoltaic energy production for the photovoltaic fleet.
 20. A methodaccording to claim 11, wherein a sum of weighting factors in theweighting factor array equals 1.